Energy Future (TXU) 10-K 2008 FY Annual report

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, 2008

— OR—

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

Commission File Number 1-12833

Energy Future Holdings Corp.

(Exact name of registrant as specified in its charter)

Texas	75-2669310
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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

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

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

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

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

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

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	Smaller reporting company	¨

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

As of February 27, 2009, there were 1,666,636,562 shares of common stock outstanding, without par value, of Energy Future Holdings Corp. (substantially all of which were owned by Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp.’s parent holding company, and none of which is publicly traded).

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

		Page
Glossary		iii
	PART I
Items 1. and 2. BUSINESS AND PROPERTIES		1
Item 1A.	RISK FACTORS	17
Item 1B.	UNRESOLVED STAFF COMMENTS	33
Item 3.	LEGAL PROCEEDINGS	34
Item 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	38
	PART II
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	39
Item 6.	SELECTED FINANCIAL DATA	40
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	44
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	108
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	115
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	224
Item 9A.	CONTROLS AND PROCEDURES	224
Item 9B.	OTHER INFORMATION	228
	PART III
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	228
Item 11.	EXECUTIVE COMPENSATION	235
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	272
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	276
Item 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	280
	PART IV
Item 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	282

i

Energy Future Holdings Corp.’s 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. 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. Energy Future Holdings Corp. will provide copies of current reports not posted on the website upon request. The information on Energy Future Holdings Corp.’s website shall not be deemed a part of, or incorporated by reference into, this report on Form 10-K. Readers should not rely on or assume the accuracy of any representation or warranty in any agreement that EFH Corp. has filed as an exhibit to this 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.

This Form 10-K and other Securities and Exchange Commission filings of Energy Future Holdings Corp. and its subsidiaries occasionally make references to EFH Corp., EFC Holdings, Intermediate Holding, TCEH, TXU Energy, Luminant, Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or any other affiliate.

ii

GLOSSARY

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

1999 Restructuring Legislation	Texas Electric Choice Plan, the legislation that restructured the electric utility industry in Texas to provide for retail competition
2007 Form 10-K	EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2007
Adjusted EBITDA	Adjusted EBITDA means EBITDA adjusted to exclude non-cash items, unusual items and other adjustments allowable under certain debt arrangements of EFH Corp. and its subsidiaries. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. EFH Corp. is providing Adjusted EBITDA in this Form 10-K (see reconciliation in Exhibits 99(b) and 99(c)) solely because of the important role that Adjusted EBITDA plays in respect of the certain covenants contained in EFH Corp.’s debt arrangements. EFH Corp. does 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 GAAP. Additionally, EFH Corp. does 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, EFH Corp.’s presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.
Ancillary services	Refers to services necessary to support the transmission of energy and maintain reliable operations for the entire transmission system.
CAIR	Clean Air Interstate Rule
Capgemini	Capgemini Energy LP, a subsidiary of Cap Gemini North America Inc. that provides business support services to EFH Corp. and its subsidiaries
CO2	carbon dioxide
Competitive Electric segment	Refers to the EFH Corp. business segment that includes TCEH and equipment salvage and resale activities related to eight cancelled coal-fueled generation units.
CREZ	Competitive Renewable Energy Zones
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.
EFC Holdings	Refers to Energy Future Competitive Holdings Company, a direct, wholly- owned subsidiary of EFH Corp. and the direct parent of TCEH.
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.
EPA	US Environmental Protection Agency
EPC	engineering, procurement and construction

iii

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
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
FIN	Financial Accounting Standards Board Interpretation
FIN 39	FIN No. 39, “Offsetting of Amounts Related to Certain Contracts — an Interpretation of APB Opinion No. 10 and FASB Statement No. 105”
FIN 46R	FIN No. 46R (Revised 2003), “Consolidation of Variable Interest Entities”
FIN 47	FIN No. 47, “Accounting for Conditional Asset Retirement Obligations — An Interpretation of FASB Statement No. 143”
FIN 48	FIN No. 48 (As Amended), “Accounting for Uncertainty in Income Taxes”
Fitch	Fitch Ratings, Ltd. (a credit rating agency)
FSP	FASB Staff Position
FSP FIN 39-1	FSP FIN No. 39-1, “Amendment of FASB Interpretation No. 39”
FSP FIN 48-1	FSP FIN No. 48-1, “Definition of Settlement in FASB Interpretation No. 48”
FSP SFAS 132(R)-1	FSP SFAS No. 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”
FSP SFAS 140-4 and FIN 46(R)-8	FSP SFAS No. 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interest in Variable Interest Entities”
FSP SFAS 157-3	FSP SFAS No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”
GAAP	generally accepted accounting principles
GWh	gigawatt-hours
historical service territory	the territory, largely in north Texas, being served by EFH Corp.’s regulated electric utility subsidiary at the time of entering retail competition on January 1, 2002
Intermediate Holding	Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.
IRS	US Internal Revenue Service
kV	kilovolts
kWh	kilowatt-hours
LIBOR	London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market.

iv

Luminant	Refers to wholly-owned subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.
Luminant Construction	Refers to the operations of TCEH established for the purpose of developing and constructing new generation facilities.
Luminant Energy	Luminant Energy Company LLC, an indirect, wholly-owned subsidiary of TCEH that engages in certain wholesale markets activities
Luminant Power	Refers to subsidiaries of TCEH engaged in electricity generation activities.
market heat rate	Heat rate is a measure of the efficiency of converting a fuel source to electricity. The market heat rate is based on the price offer of the marginal supplier in Texas (generally natural gas plants) in generating electricity and is calculated by dividing the wholesale market price of electricity by the market price of natural gas.
Merger	The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007.
Merger Agreement	Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.
Merger Sub	Texas Energy Future Merger Sub Corp, a Texas corporation and a wholly-owned subsidiary of Texas Holdings that was merged into EFH Corp. 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
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, consolidated as a variable interest entity under FIN 46R, of Intermediate Holding and the direct majority owner of Oncor.
Oncor Ring-Fenced Entities	Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor.
OPEB	other postretirement employee benefits
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act

v

Purchase accounting	The purchase method of accounting for a business combination as prescribed by SFAS 141 whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
Regulated Delivery segment	Refers to the EFH Corp. business segment, the substantial majority of which consists of the activities of Oncor.
REP	retail electric provider
RRC	Railroad Commission of Texas, which has oversight of lignite mining activity
S&P	Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies Inc. (a credit rating agency)
SARs	Stock Appreciation Rights
SARs Plan	Refers to the Oncor Electric Delivery Company Stock Appreciation Rights Plan
SEC	US Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
SFAS	Statement of Financial Accounting Standards issued by the FASB
SFAS 5	SFAS No. 5, “Accounting for Contingencies”
SFAS 34	SFAS No. 34, “Capitalization of Interest Cost”
SFAS 71	SFAS No. 71, “Accounting for the Effect of Certain Types of Regulation”
SFAS 87	SFAS No. 87, “Employers’ Accounting for Pensions”
SFAS 106	SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS 123 (R)	SFAS No. 123 (revised 2004), “Share-Based Payment”
SFAS 132 (R)	SFAS No. 132 (revised 2003), “Employers’ Disclosures About Pensions and Other Postretirement Benefits”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended and interpreted
SFAS 140	SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, a replacement of FASB Statement No. 125”
SFAS 141	SFAS No. 141, “Business Combinations”
SFAS 142	SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 144	SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS 146	SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities”
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS 158	SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”

vi

SFAS 160	SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51”
SFAS 161	SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133”
SG&A	selling, general and administrative
SO2	sulfur dioxide
Sponsor Group	Collectively, the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman Sachs & Co. (See Texas Holdings below.)
TCEH	Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of EFC Holdings and an indirect, wholly-owned subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation, wholesale and retail energy markets and development and construction 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 Secured Facilities	Refers collectively to the TCEH Initial Term Loan Facility, TCEH Delayed Draw Term Loan Facility, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 15 to the Financial Statements for details of these facilities.
TCEQ	Texas Commission on Environmental Quality
Texas Holdings	Refers to Texas Energy Future Holdings Limited Partnership, a Delaware limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.
Texas Holdings Group	Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities.
Texas Transmission	Refers to Texas Transmission Investment LLC, a Delaware limited liability company that purchased a 19.75% equity interest in Oncor in November 2008.
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.
TXU Europe	TXU Europe Limited, a subsidiary of EFH Corp. that is in administration (similar to bankruptcy) in the United Kingdom
TXU Fuel	TXU Fuel Company, a former subsidiary of TCEH
TXU Gas	TXU Gas Company, a former subsidiary of EFH Corp.
US	United States of America

vii

PART I

Items 1. and 2. BUSINESS AND PROPERTIES

See Glossary on page iii for a definition of terms and abbreviations.

EFH Corp. Business and Strategy

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

TCEH is a holding company for businesses engaged in competitive electricity market activities largely in Texas including electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales.

As of December 31, 2008, TCEH owned or leased 18,365 MW of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas-fueled generation facilities. In addition, TCEH is the largest purchaser of wind-generated electricity in Texas and the fifth largest in the US. TCEH is currently constructing three lignite/coal-fueled generation units in Texas with expected generation capacity totaling approximately 2,200 MW. Permits have been obtained for construction of the three units, which are expected to come on-line in 2009 and 2010. TCEH provides competitive electricity and related services to more than 2.2 million retail electricity customers in Texas. As of December 31, 2008, TCEH’s estimated share of the total ERCOT retail market for residential and business market electricity customers was approximately 37% and 26%, respectively (based on customer counts).

Oncor is engaged in regulated electricity transmission and distribution operations in Texas that are primarily regulated by the PUCT. Oncor provides both distribution services to retail electric providers that sell electricity to consumers and transmission services to other electricity distribution companies, cooperatives and municipalities. Oncor operates the largest transmission and distribution system in Texas, delivering electricity to approximately three million homes and businesses and operating more than 117,000 miles of transmission and distribution lines. A significant portion of Oncor’s revenues represent fees for delivery services provided to TCEH. Distribution revenues from TCEH represented 39% of Oncor’s total revenues for the year ended December 31, 2008.

EFH Corp. and Oncor have implemented certain structural and operational “ring-fencing” measures based on commitments made by Texas Holdings and Oncor to the PUCT that are intended to further separate Oncor from Texas Holdings and its other subsidiaries. These measures also serve to mitigate Oncor’s credit exposure to those entities 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. See Note 1 to Financial Statements for a description of the material features of these “ring-fencing” measures, including Oncor’s sale of additional equity interests that resulted in 19.75% of its outstanding equity interests being held by Texas Transmission, an unaffiliated investor.

At December 31, 2008, EFH Corp. had approximately 8,150 full-time employees, including approximately 2,650 employees under collective bargaining agreements.

EFH Corp.’s Market

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

1

The ERCOT market is currently divided into four regions or congestion management zones, namely: North, Houston, South and West, which reflect transmission constraints that are commercially significant and which have limits as to the amount of electricity that can flow across zones. These constraints and zonal differences can result in differences between wholesale power prices among zones. Of TCEH’s baseload generation units, 12 (including the two Oak Grove units under construction) are located in the North zone, and two (including the one Sandow unit under construction) are located in the South zone.

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’s main interconnected transmission grid. The ERCOT independent system operator is responsible for maintaining reliable operations of the bulk electricity supply system in the market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike certain other regional power markets, the ERCOT market is not a centrally dispatched power pool, and the ERCOT independent system operator does not procure energy on behalf of its members, except to the extent that it acquires ancillary services as agent for market participants. Members who sell and purchase power are responsible for contracting sales and purchases of power with other members through bilateral transactions. The ERCOT independent system operator also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.

Oncor, along with other owners of transmission and distribution facilities in Texas, assists the ERCOT independent system operator in its operations. Oncor has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated distribution service area. Oncor participates with the ERCOT independent system operator and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to meet reliability needs, increase bulk power transfer capability to remove existing constraints and interconnect generation on the ERCOT transmission grid.

The following data is derived from information published by ERCOT:

In 2008, hourly demand peaked at 62,174 MW as compared to the record hourly peak demand of 62,339 MW in 2006. The ERCOT market has limited interconnections to other markets in the US, 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.

From 1999 through 2008, over 36,000 MW of mostly natural gas-fueled and wind generation capacity has been developed in the ERCOT market. Net generation capacity in the ERCOT market for 2008 totaled 72,820 MW, excluding mothballed (idled) capacity; approximately 65% of this capacity was natural gas-fueled generation and approximately 27% of this capacity consisted of lignite/coal and nuclear-fueled baseload generation. ERCOT currently has a target reserve margin level of 12.5%; the reserve margin is projected by ERCOT to be 15.8% in 2009, 21.2% in 2010, and drop to 15.8% by 2014. This projection does not include events occurring after December 2008, such as EFH Corp.’s filing with ERCOT to retire or mothball approximately 4,000 MW of natural gas-fueled units as discussed below under “Natural Gas-Fueled Generation Assets.” Reserve margin is the difference between system generation capability and anticipated peak load.

Natural gas-fueled generation is the predominant electricity capacity resource in the ERCOT market and accounted for approximately 43% of the electricity produced in the ERCOT market in 2008. Because of the significant natural gas-fueled capacity and the ability of such plants to more readily increase or decrease production when compared to baseload generation, marginal demand for electricity is usually met by natural gas-fueled plants. As a result, wholesale electricity prices in ERCOT are highly correlated with natural gas prices.

2

EFH Corp.’s Strategies

Each of EFH Corp.’s businesses focuses its operations on key drivers for that business, as described below:

• TCEH focuses on optimizing its existing generation fleet to provide safe, reliable and cost-competitive electricity, developing and constructing additional environmentally considerate generation capacity to help meet the growing demand for electricity in Texas and providing high quality service and innovative energy products to retail customers.

• Oncor focuses on delivering electricity in a safe and reliable manner, minimizing service interruptions and investing in its transmission and distribution infrastructure to serve its growing customer base.

Other elements of EFH Corp.’s strategy include:

• Increase value from existing businesses. EFH Corp.’s strategy focuses on striving for top quartile or better performance across its operations in terms of safety, reliability, cost and customer service. In establishing tactical objectives, EFH Corp. incorporates 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 EFH Corp. lives, works and serves;

• 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;

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

An example of how EFH Corp. applies these principles is an ongoing program to drive productivity improvements in generation operations through application of lean operating techniques and deployment of a high-performance industrial culture.

• Pursue growth opportunities across business lines. EFH Corp.’s scale in its operating businesses allows it to take part in large capital investments, such as new generation projects and investments in the transmission and distribution system, with a smaller fraction of overall capital at risk and with an enhanced ability to streamline costs. EFH Corp. will also explore smaller-scale growth initiatives (such as midstream natural gas pipeline opportunities in the Barnett Shale area) that are not expected to be material to its performance over the near term but can enhance its growth profile over time. Specific growth initiatives include:

• Construct three new lignite-fueled generation facilities with onsite lignite fuel supplies. Pursue new generation opportunities to help meet ERCOT’s growing electricity needs over the longer term from a diverse range of alternatives such as nuclear, renewable energy, wind and advanced coal technologies.

• Profitably increase 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 pioneering energy efficiency initiatives and service offerings.

• Invest in transmission and distribution technology upgrades, including advanced metering systems and energy efficiency initiatives, and construct new transmission and distribution facilities to meet the needs of the growing Texas market. These growth initiatives benefit from regulatory capital recovery mechanisms known as “capital trackers” that enable adequate and timely recovery of transmission and advanced metering investments through regulated rates.

3

• Reduce the volatility of cash flows through a commodity risk management strategy. A key component of EFH Corp.’s risk management strategy is its plan to hedge approximately 80% of the natural gas price risk exposure of its baseload generation output on a rolling five-year basis. Taking into consideration the estimated portfolio impacts of retail electricity sales, EFH Corp. has executed natural gas hedging transactions that result in EFH Corp. having effectively hedged approximately 81% of its expected baseload generation natural gas price exposure (on an average basis) for 2009 through 2013 assuming an 8.0 market heat rate. The strong historical correlation between natural gas prices and wholesale electricity prices in the ERCOT market combined with the significant liquidity in certain natural gas markets provides an opportunity for management of EFH Corp.’s exposure to natural gas prices. As of January 30, 2009, approximately 2.0 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 250,000 GWh at an assumed 8.0 market heat rate) have been effectively sold forward over the period from 2009 to 2014, at average annual prices ranging from $7.20 per MMBtu to $8.10 per MMBtu. Certain of the hedging transactions are directly secured with a first-lien interest in TCEH’s assets, which minimizes liquidity requirements because no cash or letter of credit posting is required. In addition, the uncapped TCEH Commodity Collateral Posting Facility, which is also secured by a first-lien interest in TCEH’s assets, supports the margin requirements for a significant portion of the remaining hedging transactions. Consequently, as of December 31, 2008, more than 95% of the hedging transactions were secured or supported by first-lien interests in TCEH’s assets and result in no direct liquidity exposure.

• Pursue new environmental initiatives. EFH Corp. is committed to continue to operate in compliance with all environmental laws, rules and regulations and to reduce its impact on the environment. EFH Corp.’s Sustainable Energy Advisory Board advises in the pursuit of technology development opportunities that reduce EFH Corp.’s 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. In addition, EFH Corp. is focused on and is pursuing opportunities to reduce emissions from its existing and new lignite/coal-fueled generation units in the ERCOT market. EFH Corp. has voluntarily committed to reduce emissions of mercury, NOx and SO₂ at its existing units, so that the total of those emissions from both existing and new lignite/coal-fueled units is 20% below 2005 levels. EFH Corp. expects to make these reductions through a combination of investment in new emission control equipment, new coal cleaning technologies and optimizing fuel blends. In addition, EFH Corp. expects to invest $400 million over a five-year period that began in 2008 in programs designed to encourage customer electricity demand efficiencies, representing $200 million more than amounts planned to be invested by Oncor to meet regulatory requirements. EFH Corp. invested $64 million in these programs in 2008.

Seasonality

A significant portion of EFH Corp.’s revenues is derived from the amount of electricity it sells or distributes. As a result, the revenues and results of operations of EFH Corp. are subject to seasonality, weather conditions and other changes in electricity usage, with revenues being higher during the warmer months.

Operating Segments

EFH Corp. has aligned and reports its business activities as two operating segments: the Competitive Electric segment (primarily represented by TCEH) and the Regulated Delivery segment (primarily represented by Oncor). See Note 27 to the Financial Statements for additional financial information for the segments.

Competitive Electric Segment

Commodity risk management and allocation of financial resources is performed at the Competitive Electric segment (TCEH) level. However, for purposes of operational accountability and performance management, the segment has been divided into Luminant (i.e., Luminant Power, Luminant Energy and Luminant Construction) and TXU Energy. The operations of Luminant Power, Luminant Energy and TXU Energy are conducted through separate legal entities.

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Luminant Power — Luminant Power’s existing electricity generation fleet consists of 19 plants in Texas with total installed nameplate generating capacity as of December 31, 2008 as shown in the table below:

Fuel Type	Installed Nameplate Capacity (MW)	Number of Plants	Number of Units (a)
Nuclear	2,300	1	2
Lignite/coal	5,837	4	9
Natural gas (b)(c)	10,228	14	45
Total	18,365	19	56

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

(b) Includes 1,329 MW representing five units mothballed and not currently available for dispatch. See “Natural Gas-Fueled Generation Assets” below regarding the planned retirement and mothballing of additional units.

(c) Includes 1,000 MW representing 11 units currently operated for unaffiliated third-parties.

The generation plants are located primarily on land owned in fee. Nuclear and lignite/coal-fueled (baseload) plants are generally scheduled to run at capacity except for periods of scheduled maintenance activities or, in the case of lignite/coal units, backdown due to periods of low demand. The natural gas-fueled generation units supplement the baseload generation capacity in meeting consumption in peak demand periods as production from a certain number of these units can more readily be ramped up or down as demand warrants.

Nuclear Generation Assets — Luminant Power operates two nuclear generation units at the Comanche Peak plant, 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 2008. 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, excluding the 55-day outage in 2007 to refuel and replace the steam generators and reactor vessel head in Unit 1, the refueling outage period per unit has ranged from a high of 21 days in 2008 to a low of 18 days in 2006. The Comanche Peak plant operated at a capacity factor of 98.8% in 2006, which represents top decile performance when compared to all US nuclear generation facilities, 93.5% in 2007, reflecting the planned extended refueling outage to replace the steam generator and reactor vessel head in Unit 1 and 95.2% in 2008, reflecting refueling of both units.

Luminant Power has contracts in place for all of its nuclear fuel conversion services through 2009 and 71% of its requirements through 2015. In addition, Luminant Power has contracts for the acquisition of 96% of its uranium requirements for 2009, and for 94% of its nuclear fuel enrichment services through 2009, as well as all of its nuclear fuel fabrication services through 2018.

Contracts for the acquisition of additional raw uranium and nuclear fuel conversion services through 2021 and 2017, respectively, are being negotiated. Additional offers to ensure a portion of nuclear fuel enrichment services through 2021 are under review. Luminant Power does not anticipate any significant difficulties in acquiring raw uranium and contracting for associated conversion services and enrichment in the foreseeable future.

Luminant Power believes its on-site used nuclear fuel storage capability is sufficient for a minimum of five years. The nuclear industry is continuing to review ways to enhance security of used-fuel storage with the NRC to fully utilize physical storage capacity. Accordingly, Luminant Power is actively reviewing alternatives for used-fuel storage, including evaluation of industry techniques such as dry cask storage.

The Comanche Peak nuclear generation units have an estimated useful life of 60 years from the date of commercial operation. Therefore, assuming that Luminant Power 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, plant 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 state law, is funded from Oncor’s customers through an ongoing delivery surcharge. (See Note 20 to Financial Statement for discussion of the decommissioning trust fund.)

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Nuclear insurance provisions are discussed in Note 16 to Financial Statements.

Nuclear Generation Development —In September 2008, EFH Corp. filed a combined operating license application with the NRC for two new nuclear generation facilities, each with approximately 1,700 MW (gross capacity), at its existing Comanche Peak nuclear generation site. The application was accepted by the NRC for review in December 2008. In connection with the filing of the application, in January 2009, a subsidiary of EFH Corp. and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. Under the terms of the joint venture, known as Comanche Peak Nuclear Power Company LLC, a subsidiary of EFH Corp. holds an 88% ownership interest in the company, and MHI has a 12% stake.

In September 2008, EFH Corp. filed Part I of its loan guarantee application with the DOE for financing related to the proposed units. In December 2008, EFH Corp. filed Part II of the application with the DOE. The DOE continues to review the Part II application, and in accordance with DOE regulations, EFH Corp. intends to file a “Follow-On Submission,” updating its Part II application, in March 2009.

Lignite/Coal-Fueled Generation Assets — Luminant Power’s existing lignite/coal-fueled generation fleet capacity totals 5,837 MW and consists of the Big Brown (2 units), Monticello (3 units), Martin Lake (3 units) and Sandow (1 unit) plants. These plants are generally operated at full capacity to help meet the load requirements in ERCOT. Maintenance outages are scheduled during off-peak demand periods. Over the last three years, the total annual scheduled and unscheduled outages per unit averaged 32 days. Luminant Power’s lignite/coal-fueled generation fleet operated at a capacity factor of 89.1% in 2006, 90.9% in 2007 and 87.6% in 2008, which represents top quartile performance of US coal-fueled generation facilities. The 2008 performance reflects extended unplanned outages at several units.

Approximately 57% of the fuel used at Luminant Power’s lignite/coal-fueled generation plants in 2008 was supplied from lignite reserves owned in fee or leased surface-minable deposits dedicated to the Big Brown, Monticello and Martin Lake plants, which were constructed adjacent to the reserves. Luminant Power owns in fee or has under lease an estimated 942 million tons of lignite reserves dedicated to its generation plants, including the Oak Grove generation facilities being constructed and 246 million tons associated with an undivided interest in the lignite mine that provides fuel for the Sandow plant. Luminant Power also owns in fee or has under lease in excess of 85 million tons of reserves not currently dedicated to specific generation plants. In 2008, approximately 23 million tons of lignite were recovered to fuel Luminant Power’s plants. Luminant Power utilizes owned and/or leased equipment to remove the overburden and recover the lignite.

Lignite mining operations include extensive reclamation activities that return the land to productive uses such as wildlife habitats, commercial timberland and pasture land. In 2008, Luminant Power reclaimed 1,605 acres of land. In addition, EFH Corp. planted more than 1.4 million trees in 2008, the majority of which were part of the reclamation effort.

Luminant Power supplements its lignite fuel at Big Brown, Monticello and Martin Lake 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 Power’s generation plants by railcar. Based on its current usage, Luminant Power believes that it has sufficient lignite reserves for the foreseeable future and has contracted 98% of its western coal resources and all of the related transportation through 2009, with discussions and negotiations underway related to contracts for 2010 and beyond.

Natural Gas-Fueled Generation Assets — Luminant Power’s fleet of 45 natural gas-fueled generation units consists of 7,899 MW of currently available capacity, 1,000 MW of capacity being operated for unaffiliated third parties, pursuant to the direction of the unaffiliated third parties, and 1,329 MW of capacity currently mothballed (idled). The natural gas-fueled units predominantly serve as peaking units that can be ramped up or down as demand warrants.

In February 2009, Luminant notified ERCOT of its plans to retire 11 of its natural gas-fueled units, totaling 2,229 MW of capacity (2,341 MW installed nameplate capacity), in May 2009 and mothball (idle) an additional four units, totaling 1,596 MW of capacity (1,675 MW of installed nameplate capacity), in September 2009. ERCOT has 90 days from the date of Luminant’s notification to request additional information or provide feedback on Luminant’s proposed changes to the operation of these units. See Note 6 to Financial Statements regarding impairment of the natural gas-fueled fleet.

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Luminant Energy — The Luminant Energy wholesale operations play a pivotal role in TCEH’s business portfolio by optimally dispatching the generation fleet, sourcing TXU Energy’s and other customers’ electricity requirements and managing commodity price risk.

TCEH manages commodity price exposure across the complementary Luminant generation and TXU Energy retail businesses on a portfolio basis. Under this approach, Luminant Energy manages the risks of imbalances between generation supply and sales load, which primarily represent 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 markets activities that include physical purchases and sales and transacting in financial instruments.

Luminant Energy manages this commodity price and heat rate exposure through asset management and hedging activities. Luminant Energy provides TXU Energy and other wholesale customers with electricity and related services to meet their retail customers’ demands and the operating requirements of ERCOT. Luminant Energy also sells forward generation and seeks to maximize the economic value of the generation fleet. In consideration of operational production and customer consumption levels that can be highly variable, as well as opportunities for long-term purchases and sales with large wholesale market participants, Luminant Energy buys and sells electricity in short-term transactions and executes longer-term forward electricity purchase and sales agreements. Luminant Energy 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.

In its hedging activities, Luminant Energy enters into contracts for the physical delivery of electricity and natural gas, exchange traded and “over-the-counter” financial contracts and bilateral contracts with producers, generators and end-use customers. A major part of these hedging activities is a long-term hedging program, described above under “EFH Corp.’s Strategies”, designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, principally utilizing natural gas-related financial instruments.

Luminant Energy also dispatches Luminant Power’s available natural gas-fueled generation capacity. Luminant Energy’s dispatching activities are performed through a centrally managed real-time operational staff that synthesizes operational activities across the fleet and interfaces with various wholesale market channels. Luminant Energy coordinates the overall commercial strategy for these plants working closely with Luminant Power. In addition, Luminant Energy manages the natural gas and fuel-oil procurement requirements for Luminant Power’s natural gas-fueled generation fleet.

Luminant Energy engages in commercial operations such as physical purchases, storage and sales of natural gas, electricity and natural gas trading and third-party energy management. Luminant Energy’s natural gas operations include direct purchases from natural gas producers, transportation agreements, storage leases and commercial retail sales. Luminant Energy currently manages approximately 15 billion cubic feet of natural gas storage capacity.

Luminant Energy manages 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 and limits are enforced to comply with the established risk policy. Luminant Energy 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.

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Luminant Construction — Luminant Construction is developing three new lignite-fueled units in Texas with total estimated capacity of approximately 2,200 MW. The three units consist of one new generation unit at a site leased from Alcoa Inc. that is adjacent to an existing owned lignite-fueled generation unit (Sandow) and two units at an owned site (Oak Grove) that was originally slated for the construction of a generation plant a number of years ago. Aggregate cash capital expenditures for these three units are expected to total approximately $3.25 billion including all construction, site preparation and mining development costs, of which approximately $2.7 billion was spent as of December 31, 2008. 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 are estimated to total approximately $5.0 billion upon completion.

Agreements were executed with EPC contractors, Bechtel Power Corporation and Fluor Enterprises, Inc., to engineer and construct the units at Sandow and Oak Grove, respectively. Design and procurement activities for the three units are essentially complete and construction is well underway. Permits for the construction of all three units have been obtained. The expected commercial operation dates of the units remain essentially on schedule and are as follows: Sandow in mid 2009 and Oak Grove’s two units in late 2009 and mid 2010, respectively.

The development program includes up to $500 million for investments in state-of-the-art emissions controls for the three new units. The development program also includes an environmental retrofit program under which Luminant Construction plans to install additional environmental control systems at Luminant Power’s existing lignite/coal-fueled generation facilities. Estimated capital expenditures associated with these additional environmental control systems total approximately $1.0 billion to $1.3 billion, of which $219 million was spent through 2008. Luminant Construction has not yet completed all detailed cost and engineering studies for the additional environmental systems, and the cost estimates could change materially as Luminant Construction determines the details of and further evaluates the engineering and construction costs related to these investments.

TXU Energy — TXU Energy serves more than 2.2 million residential and commercial retail electricity customers in Texas. 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 expected to continue to be 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 continues to market its services in Texas to add new customers and to retain its existing customers. As of December 31, 2008, there were more than 130 active REPs certified to compete within the state of Texas.

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, system and other customer care enhancements are being implemented to further improve customer satisfaction. TXU Energy offers a wide range of residential products to meet various customer needs, currently more than any retailer in the ERCOT market. Starting in 2008, TXU Energy is investing $100 million over the next five years, including $6 million spent in 2008, in energy efficiency initiatives as part of a program to offer customers a broad set of innovative energy products and services.

From March to October 2007, TXU Energy implemented price reductions totaling 15% for residential customers in EFH Corp.’s historical service territory who had not already switched from the basic month-to-month plan to one of the other pricing plans offered by TXU Energy. TXU Energy provided price protection to these customers through December 2008. In addition, TXU Energy committed in 2006 to not increase prices above then current levels through 2009 for qualifying residential customers who remain on certain plans with rates that were then equal to the formerly regulated rate.

Regulation —Luminant Power 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 plant. NRC regulations govern the granting of licenses for the construction and operation of nuclear-fueled generation plants and subject such plants to continuing review and regulation. Luminant Energy 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.

Luminant Power and Luminant Energy are also subject to the jurisdiction of the PUCT’s oversight of the competitive ERCOT wholesale electricity market. PUCT rules do not set wholesale power prices in the market but do provide certain limits and framework for such pricing and market behavior.

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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.

Regulated Delivery Segment

The Regulated Delivery segment primarily consists of the operations of Oncor. Oncor is a regulated electricity transmission and distribution company that provides the essential service of delivering electricity safely, reliably and economically to end-use consumers through its distribution systems, as well as providing transmission grid connections to merchant generation plants and interconnections to other transmission grids in Texas. This territory has an estimated population in excess of seven million, about one-third of the population of Texas, and comprises 92 counties and over 370 incorporated municipalities, including Dallas/Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler and Killeen. Oncor’s transmission and distribution assets are located principally in the north-central, eastern and western parts of Texas. Most of Oncor’s power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way as permitted by law. Oncor’s transmission and distribution rates are regulated by the PUCT.

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

Performance —Oncor achieved market-leading electricity delivery performance in six out of seven key PUCT market metrics in 2008. These metrics measure the success of transmission and distribution companies in facilitating customer transactions in the competitive Texas electricity market. In July 2007, the PUCT established new performance standards, and Oncor has implemented a plan seeking to achieve compliance with these standards during 2009.

Investing in Infrastructure and Technology —In 2008, Oncor invested over $882 million in its network to construct, rebuild and upgrade transmission lines and associated facilities, to extend the distribution infrastructure, and to pursue certain initiatives in infrastructure maintenance and information technology. Reflecting its commitment to infrastructure, in September 2008, Oncor and several other ERCOT utilities filed with the PUCT a plan to participate in the construction of transmission improvements designed to interconnect existing and future renewable energy facilities to transmit electricity from Competitive Renewable Energy Zones (CREZ) identified by the PUCT. This plan included the joint parties’ plans to construct and operate all of the CREZ transmission facilities (CREZ Transmission Plan). Several other parties, including ERCOT and non-ERCOT entities, also filed CREZ Transmission Plans. Hearings on the CREZ Transmission Plan proposals were held in December 2008, and at a January 2009 open meeting, the PUCT assigned approximately $1.3 billion of CREZ construction projects to Oncor. Oncor anticipates that a written order reflecting the PUCT’s decisions will be entered in the first quarter of 2009. The cost estimates for the CREZ construction projects are based upon analyses prepared by ERCOT. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Regulation and Rates.”

Oncor is also investing in technology initiatives that include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs.

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In 2008, Oncor acquired a vendor’s existing broadband over powerline (BPL)-based “Smart Grid” network assets in Oncor’s service territory for $90 million in cash. These network assets include BPL equipment and technology such as fiber optics, embedded sensors and software analytics that are intended to enable Oncor to better monitor its electricity distribution network over up to one-sixth of its service territory. The network assets also included certain finished goods inventory and additional components. As part of the transaction, Oncor agreed to purchase software licenses and maintenance and operation services for a three-year period for approximately $35 million, including $25 million paid at the closing of the transaction. In addition, Oncor may, at its option, purchase additional equipment and utilize additional services from the vendor that would allow Oncor to expand the BPL network to up to one-half of its service territory.

In a stipulation with several parties that was approved by the PUCT (as discussed in Note 8 to Financial Statements), Oncor committed to a variety of actions, including minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. This spending does not include the CREZ facilities.

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

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

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

Provisions of the 1999 Restructuring Legislation allow Oncor to annually update its transmission rates to reflect changes in invested capital. These provisions encourage investment in the transmission system to help ensure reliability and efficiency by allowing for timely recovery of and return on new transmission investments.

Oncor’s transmission facilities include 5,043 circuit miles of 345-kV transmission lines and 9,862 circuit miles of 138-and 69-kV transmission lines. Sixty-three generation plants totaling 37,691 MW are directly connected to Oncor’s transmission system, and 277 transmission stations and 697 distribution substations are served from Oncor’s transmission system.

Oncor’s transmission facilities have the following connections to other transmission grids in Texas:

	Number of Interconnected Lines
Grid Connections	345kV	138kV	69kV
Centerpoint Energy Inc.	8	—	—
American Electric Power Company, Inc (a)	4	7	12
Lower Colorado River Authority	6	20	3
Texas Municipal Power Agency	8	9	—
Texas New Mexico Power	2	9	11
Brazos Electric Power Cooperative	4	99	21
Rayburn Country Electric Cooperative	—	31	7
City of Georgetown	—	2	—
Tex-La Electric Cooperative	—	11	1
Other small systems operating wholly within Texas	—	3	2

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

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Electricity Distribution — Oncor’s electricity distribution business is responsible for the overall safe and efficient operation of distribution facilities, including electricity delivery, power quality and system reliability. These responsibilities consist of the ownership, management, construction, maintenance and operation of the distribution system within Oncor’s certificated service area. Oncor’s distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through approximately 3,080 distribution feeders.

The Oncor distribution system includes over 3.1 million points of delivery. Over the past five years, the number of Oncor’s distribution system points of delivery served, excluding lighting sites, grew an average of approximately 1.5% per year, adding approximately 33,500 points of delivery in 2008.

The Oncor distribution system consists of 56,266 miles of overhead primary conductors, 21,639 miles of overhead secondary and street light conductors, 15,277 miles of underground primary conductors and 9,497 miles of underground secondary and street light conductors. The majority of the distribution system operates at 25-kV and 12.5-kV.

Customers —Oncor’s transmission customers consist of municipalities, electric cooperatives and other distribution companies. Oncor’s distribution customers consist of more than 65 REPs in Oncor’s certificated service area, including TCEH. Distribution revenues from TCEH represented 39% of Oncor’s total revenues for 2008, and revenues from two subsidiaries of Reliant Energy, Inc., each of which is a non-affiliated REP, represented 16% of Oncor’s total revenues for 2008. No other customer represented more than 10% of Oncor’s total operating revenues. The retail customers who purchase and consume electricity delivered by Oncor are free to choose their electricity supplier from REPs who compete for their business.

Regulation and Rates —As its operations are wholly within Texas, EFH Corp. believes that Oncor is not a public utility as defined in the Federal Power Act and has been advised by its legal counsel that it is not subject to general regulation under this Act.

The PUCT has original jurisdiction over transmission and distribution rates and services in unincorporated areas and in those municipalities that have ceded original jurisdiction to the PUCT and has exclusive appellate jurisdiction to review the rate and service orders and ordinances of municipalities. Generally, PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that does not have the prior approval of the appropriate regulatory authority (PUCT or municipality with original jurisdiction). In accordance with a stipulation approved by the PUCT, Oncor filed a rate case with the PUCT (Docket No. 35717) in June 2008, based on a test year ended December 31, 2007 as discussed in Item 7, “Management’s Discussion and Analysis of Financial Condition — Regulation and Rates.”

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

Securitization Bonds—The Regulated Delivery segment includes Oncor’s wholly-owned, bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC. This financing subsidiary was organized for the limited purpose of issuing specified transition bonds in 2003 and 2004. Oncor Electric Delivery Transition Bond Company LLC issued $1.3 billion principal amount of securitization (transition) bonds to recover generation-related regulatory asset stranded costs and other qualified costs under an order issued by the PUCT in 2002.

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Environmental Regulations and Related Considerations

Global Climate Change

Background — In recent years, a growing concern has emerged nationally and internationally about global climate change and how greenhouse gas emissions (GHGs), such as CO₂, contribute to global climate change. EFH Corp. produces GHG emissions from the direct combustion of fossil fuels at its generation plants, primarily its nine lignite/coal-fueled generation plants. CO₂, methane and NOx are emitted in this combustion process, with CO₂ representing the largest portion of these GHG emissions. GHG emissions (primarily CO₂) from EFH Corp.’s combustion of fossil fuels represent the substantial majority of EFH Corp.’s total GHG emissions. EFH Corp. estimates that its generation plants produced an average of 58 million tons of CO₂ annually from 2005 to 2007. The three lignite-fueled units currently under construction that EFH Corp. estimates will come on-line in 2009 and 2010 will generate additional CO₂ emissions. EFH Corp.’s other GHG emission sources include, among other things, coal piles at its generation plants, sulfur hexafluoride in its electric operations, refrigerant from its chilling and cooling equipment, fossil fuel combustion in its motor vehicles and electricity usage at its facilities and headquarters. Because a substantial portion of the generation portfolio consists of lignite/coal-fueled generation plants and EFH Corp. is constructing three new lignite-fueled generation units, EFH Corp.’s financial condition and/or results of operations could be materially adversely affected by the enactment of laws 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 EFH Corp. regarding global climate change regulation.

Global Climate Change Legislation — Several bills 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), a tax on carbon emissions (carbon tax) and incentives for the development of low-carbon technology. 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 energy portfolio standards (RPS). There is a growing consensus that some form of legislation or regulation is likely to occur in the near future at the federal level concerning GHG emissions.

EFH Corp., through its own evaluation and working in tandem with other companies, has 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, EFH Corp. believes 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 and protect consumers. EFH Corp. contends 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, EFH Corp. participates in a voluntary electric utility industry sector climate change initiative in partnership with the DOE. EFH Corp.’s strategies are generally consistent with “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, EFH Corp. has created a Sustainable Energy Advisory Board that advises EFH Corp. on technology development opportunities that reduce the effects of EFH Corp.’s 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.

Federal Level — A number of pieces of legislation dealing with GHG have been recently proposed in the US Congress, including (i) the Lieberman-Warner America’s Climate Security Act of 2007 (Climate Security Act) and (ii) various federal RPS bills. None of this legislation has become law. The Climate Security Act would have created an economy-wide cap-and-trade program and would have required emissions to be reduced by 70% from 2005 levels from covered sources by 2050. The various federal RPS proposals have standards ranging from 20% from renewable sources by 2021 to 25% from renewable sources by 2025. President Obama has stated that he favors legislation that would (i) reduce GHG emissions by 80% by 2050 and (ii) require a federal RPS of 25% from renewable sources by 2025. The Obama Administration included in its recently published budget summary a provision for a cap-and-trade system, under which emitters of carbon dioxide or other GHG would need to purchase allowances under a federally-administered auction program, with no initial free allocations.

In April 2007, the US Supreme Court issued a decision in the case ofMassachusetts v. US Environmental Protection Agency holding that CO₂ and other GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the federal Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or in the alternative, provide a reasonable explanation why GHG emissions should not be regulated. Possible outcomes from this decision include EPA regulation of GHG emissions not only from motor vehicles but also from industrial sectors, including electricity generation, transmission and distribution facilities, under a new EPA rule. In July 2008, the EPA issued an Advanced Notice of Proposed Rulemaking (ANPR) and is currently considering public comments made regarding the potential regulation of GHG emissions by the EPA under the federal Clean Air Act.

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State and Regional Level —The 81st Session of the Texas Legislature began in January 2009. EFH Corp. expects a number of bills to be filed in the Texas Legislature that will address global climate change. EFH Corp. opposes state-by-state regulation of GHG. There are no regional initiatives concerning GHGs in which the State of Texas is a participant.

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. The US is expected to participate in this process. Recommendations will be reviewed at the UNFCCC meeting in 2009.

EFH Corp. continues to assess the risks posed by possible future legislative or regulatory changes pertaining to GHG emissions. Because the proposals described above are in their formative stages, EFH Corp. is unable to predict the potential effects on its 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 prices.

EFH Corp.’s Voluntary Energy Efficiency, Renewable Energy, and Global Climate Change Efforts — EFH Corp. is considering, or expects to be actively engaged in, business activities that could result in reduced GHG emissions including:

• Investing in Energy Efficiency or Related Initiatives by EFH Corp.’s Competitive Businesses — EFH Corp.’s competitive businesses expect to invest $100 million in energy efficiency or related initiatives over a five-year period that began in 2008, including initiatives such as the TXU Energy Power Monitor^™, an in-home display device that enables residential customers to monitor whole-house energy usage and cost in real-time, as well as projects month-end bill amounts; the TXU Energy iThermostat^™, a web-enabled programmable thermostat with load control feature for cycling off air conditioners during times of peak energy demand; the development of time-based electricity rates that are expected to work in conjunction with advanced metering infrastructure; rate plans that include electricity from renewable resources; a Compact Fluorescent Light (CFL) program that provide packages of CFLs to customers; a program to refer customers to energy efficiency contractors and provide rebates to residential customers who install energy-efficient heating and cooling systems, ceiling insulation or windows; the provision of loans to business customers for purchasing new energy efficient equipment for their facilities based on a detailed engineering design through the Energy Conservation Investment Program; the Energy Efficiency Assistance Program that delivers products and services, as well as grants through social service agencies, to improve the energy efficiency of participating low income customer homes and apartment complexes; and online energy audit tools and tips for using less electricity;

• Investing in Energy Efficiency Initiatives by Oncor — In addition to the potential energy efficiencies from advanced metering, EFH Corp. expects to invest $300 million in energy efficiency initiatives over a five-year period that began in 2008, including energy consumption and carbon emissions through such efforts as the Take a Load Off Texas Solar Photovoltaic Program, the Mobile Experience Center, and investment of over $16 million in the installation of solar photovoltaic systems in customer’s homes and facilities that is expected to result in savings of up to 4.8 million kWh of electricity;

• Participating in the CREZ Program — Oncor has been selected by the PUCT to construct approximately $1.3 billion of CREZ transmission facilities that are designed to connect existing and future renewable energy facilities to the electricity distribution system in ERCOT;

• Purchasing Electricity from Renewable Sources — EFH Corp. expects to remain a leader in the ERCOT market in providing electricity from renewable sources by purchasing up to 1,500 MW of wind power. EFH Corp.’s total wind power portfolio is currently more than 900 MW;

• Promoting the use of Solar Power — EFH Corp. also hopes to promote solar power through solar/photovoltaic cars, rebates, incentives, and/or credits. In addition, TXU Energy’s Solar Academy works with Texas school districts to teach and demonstrate the benefits of solar power;

• Investing in Technology — EFH Corp. will evaluate over the next five to ten years the development and commercialization of cleaner power plant technologies, including integrated gasification combined cycle and pulverized coal emissions technology to reduce CO₂ emission intensity, as well as related technologies such as electric cars and plug-in hybrid electric vehicles that have the potential to reduce overall GHG emissions;

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• Evaluating the Development of a New Nuclear Generation Facility — EFH Corp. has 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 emission source of baseload generation available) at its Comanche Peak nuclear generation plant. In addition, EFH Corp. has (i) filed Part I and II of 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 —EFH Corp. is engaged in a number of tree planting programs that offset GHG emissions, including its planting of over 1.4 million trees in 2008 (the majority of which were part of EFH Corp.’s mining reclamation effort) and TXU Energy’s Urban Tree Farm program under which it has planted more than 100,000 trees since the program’s inception in 2002.

Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions

The EPA has promulgated Acid Rain Program rules that require fossil-fueled plants to have sufficient SO₂ emission allowances and meet certain NO_xemission standards. EFH Corp.’s generation plants meet these SO₂ allowance requirements and NO_x emission rates.

In 2005, the EPA issued a final rule to further reduce SO₂ and NOx emissions from power plants. The SO₂ and NOx reductions required under the Clean Air Interstate Rule (CAIR), which were required to be phased in between 2009 and 2015, were based on a cap and trade approach (market-based) in which a cap was put on the total quantity of emissions allowed in 28 eastern states (including Texas). Emitters were required to have allowances for each ton emitted, and emitters were allowed to trade emissions under the cap. In July 2008, the US Court of Appeals for the D.C. Circuit (D.C. Circuit Court) vacated CAIR. In December 2008, in response to an EPA petition, the D.C. Circuit Court reversed, in part, its previous ruling. Such reversal confirmed CAIR is not valid, but allowed it to remain in place while the EPA revises CAIR to correct the previously identified shortcomings. Since the D.C. Circuit Court did not prescribe a deadline for this revision, at this time, EFH Corp. cannot predict how or when the EPA may revise CAIR. See Note 3 to Financial Statements for discussion of the impairment of emission allowances intangible assets.

In 2005, the EPA also published a final rule requiring reductions of mercury emissions from 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. Pursuant to the D.C. Circuit Court’s ruling, the EPA must begin development of rules implementing a Maximum Achievable Control Technology standard, which will likely take several years. See Item 3, “Legal Proceedings—Litigation Related to Generation Development.”

SO₂ 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. The EPA provides the option for states to use CAIR to satisfy BART reductions for electric generating units, and Texas has chosen this option. The D.C. Circuit Court decision to leave CAIR in place while the EPA revises it should allow Texas to move forward with its plans.

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In connection with EFH Corp.’s construction of three new lignite-fueled generation units in Texas, EFH Corp. has committed to reduce emissions of NO_x, SO₂ and mercury at its existing lignite/coal-fueled units such that the total of those emissions from both existing and new lignite/coal-fueled units are 20% below 2005 levels. EFH Corp. has also applied with the TCEQ to seek a “maximum achievable control technology” determination for its two Oak Grove units that are under construction and has agreed to offset any emissions above those levels. This reduction is expected to be accomplished through the installation of emissions control equipment in both the new and existing units and fuel blending at some existing units. These efforts, which will involve incremental equipment investments as well as additional costs for facility operations and maintenance in the future, will be coordinated with efforts related to applicable environmental rules to provide the most cost-effective compliance plan options.

The following are the major air quality improvements planned at EFH Corp.’s existing and new coal-fueled power plants to help meet the offset and reduction commitment:

• To reduce NO_x emissions, EFH Corp. plans to install in-duct selective catalytic reduction (SCR) systems at its Martin Lake plant. In addition, EFH Corp. plans to install selective non-catalytic reductions systems at its Monticello and Big Brown plants and improve the low-NO_x burner technology at one of its Monticello units to further reduce NO_x emissions. This is in addition to external SCR systems at the existing Sandow unit and new Oak Grove units;

• To reduce mercury emissions, all of EFH Corp.’s new and existing plants plan to use activated carbon injection — a sorbent injection system technology, and

• To reduce SO₂ emissions, EFH Corp. plans to increase use of lower-sulfur coal at various plants. In addition, the Martin Lake, Monticello and Big Brown plants plan to employ coal-cleaning technology to reduce both SO₂ and mercury emissions.

The Clean Air Act requires each state to monitor air quality for compliance with federal health standards. The standards for ozone are not being achieved in several areas of Texas. The TCEQ adopted new State Implementation Plan (SIP) rules in May 2007 to deal with eight-hour ozone standards. These rules require further NO_x emission reductions from certain EFH Corp. peaking natural gas-fueled units in the Dallas-Fort Worth area by spring 2009; EFH Corp. expects to be in compliance with these rules. In March 2008, the EPA made the eight-hour ozone standards more stringent. Since SIP rules to address attainment of these new more stringent standards will not be required for approximately four years, EFH Corp. cannot yet predict the impact of this action on its facilities.

EFH Corp. believes that it holds all required emissions permits for facilities in operation and has applied for or obtained the necessary construction permits for facilities under construction.

Water

The TCEQ and the EPA have jurisdiction over water discharges (including storm water) from facilities in Texas. EFH Corp. believes its facilities are presently in material compliance with applicable state and federal requirements relating to discharge of pollutants into water. EFH Corp. believes it holds all required waste water discharge permits from the TCEQ for facilities in operation and has applied for or obtained necessary permits for facilities under construction. EFH Corp. also believes it can satisfy the requirements necessary to obtain any required permits or renewals. Recent changes to federal rules pertaining to the Spill Prevention, Control and Countermeasure (SPCC) plans for oil-filled electrical equipment and bulk storage facilities for oil will require updating of certain of its plants and facilities. EFH Corp. has determined that SPCC plans will be required for certain substations, work centers and distribution systems by July 1, 2009, and it is currently compiling data for development of these plans.

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Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQ and the EPA. EFH Corp. believes it possesses all necessary permits for these activities from the TCEQ for its present operations. EFH Corp. is in the process of obtaining the necessary water rights permit from the TCEQ for the lignite mine that will support the Oak Grove units. Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large generation plants were published by the EPA in 2004. As prescribed in the regulations, EFH Corp. 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. EFH Corp. cannot predict the impact on its operations of the suspended existing regulations or of new regulations, if any, that replace them.

Radioactive Waste

EFH Corp. currently ships 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 Commissioners voted to approve this permit. EFH Corp. intends 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 “Competitive Electric Segment — Luminant Power — Nuclear Generation Assets” above.)

EFH Corp. believes that its on-site used nuclear fuel storage capability is sufficient for a minimum of five years. The nuclear industry is continuing to review ways to enhance security of used-fuel storage with the NRC to fully utilize physical storage capacity. Accordingly, EFH Corp. is actively reviewing alternatives for used-fuel storage, including evaluation of industry techniques such as dry cask storage.

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 EFH Corp. facilities. EFH Corp. believes it is in material compliance with all applicable solid waste rules and regulations. In addition, EFH Corp. has registered solid waste disposal sites and has obtained or applied for permits required by such regulations. In December 2008, an ash impoundment facility at another company’s site in another state ruptured releasing a significant quantity of coal ash slurry. No impoundment failures of this nature have ever occurred at any EFH Corp. impoundments, which are inspected on a regular basis. In addition, groundwater monitoring wells are sampled routinely to ensure compliance with all applicable regulations. EFH Corp. is unable to predict future impacts on its financial condition or operations due to any legislative or regulatory actions that may be taken in response to the impoundment failure mentioned above.

Environmental Capital Expenditures

Capital expenditures for EFH Corp.’s environmental projects totaled $191 million in 2008 and are expected to total approximately $175 million in 2009 consisting primarily of environmental projects at existing lignite/coal-fueled generation plants. These amounts are exclusive of emissions control equipment investment planned as part of the three-unit generation development program, which is expected to total up to $500 million over the construction period. See discussion above under “Luminant Construction” regarding planned investments in emissions control systems.

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Item 1A. RISK FACTORS

Some important factors, in addition to others specifically addressed in Management’s Discussion and Analysis of Financial Condition and Results of Operations, that could have a material negative impact on EFH Corp.’s operations, financial results and financial condition, or could cause EFH Corp.’s actual results or outcomes to differ materially from any projected outcome contained in any forward-looking statement in this report, include:

Risks Relating to Substantial Indebtedness and Debt Agreements

EFH Corp.’s substantial leverage could adversely affect its ability to raise additional capital to fund its operations, limit its ability to react to changes in the economy or its industry, expose EFH Corp. to interest rate risk to the extent of its variable rate debt and prevent EFH Corp. from meeting obligations under the various debt agreements governing its indebtedness.

EFH Corp. is highly leveraged. As of December 31, 2008, EFH Corp.’s consolidated principal amount of debt (short term borrowings and long-term debt, including amounts due currently) totaled $43.3 billion (see Note 15 to Financial Statements). EFH Corp.’s substantial leverage could have important consequences, including:

• making it more difficult for EFH Corp. to make payments on its indebtedness;

• requiring a substantial portion of cash flow from operations to be dedicated to the payment of principal and interest on indebtedness, therefore reducing EFH Corp.’s ability to use its cash flow to fund operations, capital expenditures and future business opportunities and execute its strategy;

• increasing vulnerability to adverse economic, industry or competitive developments;

• exposing EFH Corp. to the risk of increased interest rates because 6% of its long-term borrowings are at variable rates of interest;

• limiting ability to make strategic acquisitions or causing EFH Corp. to make non-strategic divestitures;

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

• limiting ability to adjust to changing market conditions and placing EFH Corp. at a competitive disadvantage compared to competitors who are less highly leveraged and who therefore, may be able to take advantage of opportunities that EFH Corp. cannot due to its substantial leverage.

Despite EFH Corp.’s current high indebtedness level, it may still be able to incur substantially more indebtedness. This could further exacerbate the risks associated with EFH Corp.’s substantial indebtedness.

EFH Corp. may be able to incur additional indebtedness in the future. Although EFH Corp.’s debt agreements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and under certain circumstances, the amount of indebtedness that could be incurred in compliance with these restrictions could be substantial. If new debt is added to EFH Corp.’s existing debt levels, the related risks that EFH Corp. now faces would intensify.

Increases in interest rates may negatively impact EFH Corp.’s operating results and financial condition.

Certain of EFH Corp.’s borrowings, to the extent the interest rate is not fixed by interest rate swaps, are at variable rates of interest. An increase in interest rates would have a negative impact on EFH Corp.’s results of operations by causing an increase in interest expense.

At December 31, 2008, EFH Corp. had $2.6 billion aggregate principal amount of variable rate long-term indebtedness (excluding $1.25 billion of long-term borrowings associated with the TCEH Letter of Credit Facility that are invested at a variable rate), taking into account interest rate swaps that fix the interest rate on $17.55 billion in notional amount of variable rate indebtedness. As a result, as of December 31, 2008, the impact of a 100 basis point increase in interest rates would increase EFH Corp.’s annual interest expense by approximately $26 million. See discussion of interest rate swap transactions in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Activities and Events — Interest Rate Swap Transactions.”

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EFH Corp.’s interest expense for the year ended December 31, 2008 was $4.935 billion.

EFH Corp.’s debt agreements contain restrictions that limit flexibility in operating its businesses.

EFH Corp.’s debt agreements contain various covenants and other restrictions that limit the ability of EFH Corp. and/or its restricted subsidiaries to engage in specified types of transactions and may adversely affect the ability to operate its businesses. These covenants and other restrictions limit EFH Corp.’s and its restricted subsidiaries’ ability to, among other things:

• incur additional indebtedness 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;

• consolidate, merge, sell or otherwise dispose of all or substantially all of EFH Corp.’s assets;

• enter into transactions with EFH Corp.’s affiliates, and

• repaying, repurchasing or modifying certain subordinated and other material debt.

There are a number of important limitations and exceptions to these covenants and other restrictions. See Note 15 to Financial Statements for a description of these covenants and other restrictions.

Under the TCEH Senior Secured Facilities, TCEH is required to maintain a leverage ratio below specified levels. TCEH’s ability to maintain its leverage ratio below such levels can be affected by events beyond its control, and there can be no assurance that it will meet any such ratio.

A breach of any of these covenants or restrictions could result in an event of default under one or more of EFH Corp.’s debt agreements, including as a result of cross default provisions. Upon the occurrence of an event of default under one of the debt agreements, the lenders could elect to declare all amounts outstanding under that debt agreement to be immediately due and payable and terminate all commitments to extend further credit. Such actions by those lenders could cause cross defaults under EFH Corp.’s other indebtedness. If EFH Corp. was unable to repay those amounts, the lenders could proceed against any collateral granted to them to secure such indebtedness. If lenders accelerate the repayment of borrowings, EFH Corp. may not have sufficient assets and funds to repay those borrowings.

In addition, as described in Note 1 to Financial Statements, EFH Corp. and Oncor have implemented a number of “ring-fencing” measures to further separate Oncor, its immediate parent, Oncor Holdings, and Oncor Holdings’ other subsidiaries, from Texas Holdings and its other subsidiaries. Those measures include:

• Oncor being treated as an Unrestricted Subsidiary with respect to certain EFH Corp. indebtedness;

• Oncor not being restricted from incurring its own indebtedness, and

• Oncor not guaranteeing or pledging any of its assets to secure the indebtedness of Texas Holdings and its other subsidiaries.

Under the terms of TCEH’s debt agreements, TCEH is restricted from making certain payments to EFH Corp.

EFH Corp. is a holding company and substantially all of its consolidated assets are held by its subsidiaries. As of December 31, 2008, TCEH and its subsidiaries held approximately 73% of EFH Corp.’s consolidated assets and represented approximately 86% of EFH Corp.’s consolidated revenues. Accordingly, EFH Corp. depends upon TCEH for a significant amount of its cash flows and ability to pay its obligations. However, under the terms of TCEH’s debt agreements, TCEH is restricted from making certain payments, including dividends and loans, to EFH Corp., except in limited circumstances.

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Risks Relating to Structure

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

EFH Corp.’s cash flows and ability to meet its obligations are largely dependent upon the earnings of its subsidiaries and the payment of such earnings to EFH Corp. in the form of dividends, distributions, loans or otherwise, and repayment of loans or advances from EFH Corp. These subsidiaries are separate and distinct legal entities and have no obligation to provide EFH Corp. with funds for its payment obligations. Any decision by a subsidiary to provide EFH Corp. with funds for its payment obligations, whether by dividends, distributions, loans or otherwise, will depend on, among other things, the subsidiary’s results of operations, financial condition, cash requirements, contractual restrictions and other factors. In addition, a subsidiary’s ability to pay dividends may be limited by covenants in its existing and future debt agreements or applicable law. Further, the distributions that may be paid by Oncor are limited through December 31, 2012, to an amount not to exceed Oncor’s net income (determined in accordance with GAAP, subject to certain defined adjustments, including goodwill impairments), and are further limited by an agreement that Oncor’s regulatory capital structure will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.

Because EFH Corp. is a holding company, its obligations to its creditors are structurally subordinated to all existing and future liabilities and existing and future preferred stock of its subsidiaries. Therefore, EFH Corp.’s rights and the rights of its creditors to participate in the assets of any subsidiary in the event that such a subsidiary is liquidated or reorganized are subject to the prior claims of such subsidiary’s creditors and holders of the subsidiary’s preferred stock. To the extent that EFH Corp. may be a creditor with recognized claims against any such subsidiary, EFH Corp.’s claims would still be subject to the prior claims of such subsidiary’s creditors to the extent that they are secured or senior to those held by EFH Corp. Subject to restrictions contained in financing arrangements, EFH Corp.’s subsidiaries may incur additional indebtedness and other liabilities.

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

Upon the consummation of the Merger, EFH Corp. and Oncor implemented certain structural and operational “ring-fencing” measures based on principles articulated by rating agencies and commitments made by Texas Holdings and Oncor to the PUCT and the FERC to further separate Oncor from the Texas Holdings Group. These measures were put into place to mitigate Oncor’s credit exposure to those entities 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 implemented by EFH Corp. and Oncor, a majority of the members of the board of directors of Oncor are required to be, and are, independent from EFH Corp. Other than the initial independent directors that were appointed within 30 days of the consummation of the Merger, the independent directors are required to be appointed by the nominating committee of Oncor Holdings. The organizational documents of Oncor give these independent directors, acting by majority vote, and, during certain periods, any director designated by Texas Transmission, the express right to prevent distributions from Oncor if they determine that it is in the best interests of Oncor to retain such amounts to meet expected future requirements. Accordingly, there can be no assurance that Oncor will make any distributions to EFH Corp.

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In addition, Oncor’s organizational documents limit Oncor’s distributions to EFH Corp. through 2012 to Oncor’s net income and prohibit Oncor from making any distribution to EFH Corp. so long as and to the extent that such distribution would cause Oncor’s debt-to-equity ratio for regulatory purposes to be above the debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. In February 2009, the PUCT awarded Oncor investment of approximately $1.3 billion to construct transmission lines and facilities associated with its Competitive Renewable Energy Zones (CREZ) Transmission Plan (see discussion in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Regulation and Rates). With the award, it is likely Oncor will incur additional debt. In addition, Oncor may incur additional debt in connection with other investments in infrastructure or technology. Accordingly, there can be no assurance that Oncor’s debt-to-equity ratio for regulatory purposes will not exceed the debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, thereby restricting Oncor from making any distributions to EFH Corp. until such time as CREZ investments are reflected in Oncor’s rates and are generating net income.

Risks Relating to Businesses

EFH Corp.’s businesses are subject to ongoing complex governmental regulations and legislation that have impacted, and may in the future impact, its businesses and/or results of operations.

EFH Corp.’s 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. EFH Corp. will need to continually adapt to these changes. For example, the Texas retail electricity market became competitive in January 2002, and the introduction of competition has resulted in, and may continue to result in, declines in customer counts and sales volumes.

EFH Corp.’s 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 and the Energy Policy Act of 2005), changing governmental policy and regulatory actions (including those of the PUCT, the Electric Reliability Organization, the Texas Regional Entity, the RRC, the TCEQ, the FERC, the EPA and the NRC) and the rules, guidelines and protocols of ERCOT with respect to matters including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, construction and operation of transmission facilities, acquisition, disposal, depreciation and amortization of regulated assets and facilities, recovery of costs and investments, decommissioning costs, return on invested capital for regulated businesses, market behavior rules, present or prospective wholesale and retail competition and environmental matters. TCEH, along with other market participants, is subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA that are administered by the PUCT and ERCOT, and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior and other competition-related rules and regulations under the Federal Power Act that are administered by the FERC. Changes in, revisions to, or reinterpretations of existing laws and regulations (for example, with respect to prices at which TCEH may sell electricity, the required permits for the three lignite-fueled generation units currently under construction or the cost of emitting greenhouse gases) may have an adverse effect on EFH Corp.’s businesses.

In 2007, the Texas legislature adopted legislation that likely requires prior PUCT approval for certain direct or indirect dispositions of Oncor, and ensures that the PUCT will have authority to enforce commitments made in a filing on or after May 1, 2007 under PURA Section 14.101 (such as the filing made by Texas Holdings and Oncor in April 2007). Several pieces of legislation introduced in the Texas legislature during 2007, if passed, may have had a material impact on EFH Corp. and its financial prospects, including, for example, legislation that would have:

• required EFH Corp. to separate its subsidiaries into two or three stand-alone companies, which could have resulted in a significant tax cost or the sale of assets for an amount EFH Corp. would not have considered to be full value;

• required divestiture of significant wholesale power generation assets, which also could have resulted in a significant tax cost or the sale of assets for an amount EFH Corp. would not have considered to be full value, and

• given new authority to the PUCT to cap retail electricity prices.

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Although none of this legislation was passed, there can be no assurance that future action of the Texas Legislature, which could be similar or different from the proposals considered by the 2007 Texas Legislature, will not have a material adverse effect on EFH Corp. and its financial prospects. The Texas Legislature’s next session began in January 2009. The outcome of any legislation that may be considered by the Texas Legislature in 2009 is uncertain. Such legislation could have an adverse effect on EFH Corp.’s business and financial prospects.

Litigation or legal proceedings could expose EFH Corp. to significant liabilities and reputation damage, and have a material adverse effect on its results of operations, and the litigation environment in which EFH Corp. operates poses a significant risk to its businesses.

EFH Corp. is involved in the ordinary course of business in a number of lawsuits involving employment, commercial, environmental and injuries and damages issues, among other matters, such as challenges (to which EFH Corp. may or may not be a direct party) to the permits that have been issued or may be issued for the new lignite-fueled generation units currently under construction. EFH Corp. evaluates 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 assessments and estimates, EFH Corp. establishes reserves and discloses the relevant litigation claims or legal proceedings, as appropriate. These assessments 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 assessments and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on EFH Corp.’s results of operations.

In addition, judges and juries in the State of Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage and business tort cases. EFH Corp. uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment in the state of Texas poses a significant business risk.

EFH Corp. is also exposed to the risk that it may become the subject of regulatory investigations. See Item 3 “Legal Proceedings — Regulatory Investigations and Reviews”.

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

TXU Energy faces competition for customers. Competitors may offer lower prices and other incentives, which, despite TXU Energy’s long-standing relationship with customers, may attract customers away from TXU Energy.

In some retail electric markets, TXU Energy’s 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, TXU Energy 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 TXU Energy. Some of these competitors or potential competitors may be larger or better capitalized than TXU Energy. If there is inadequate potential margin in these retail electric markets, it may not be profitable for TXU Energy to compete in these markets.

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TCEH’s revenues and results of operations may be negatively impacted by decreases in market prices for power, decreases in natural gas prices, and/or decreases in market heat rates.

TCEH, EFH Corp.’s largest business, is not guaranteed any rate of return on capital investments in its competitive businesses. EFH Corp. markets and trades electricity and natural gas, including electricity from its own generation facilities and generation contracted from third parties, as part of its wholesale markets operation. TCEH’s results of operations depend in large part upon 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 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 EFH Corp.’s generation facilities is purchased under short-term contracts. Prices of fuel, including natural gas, coal, and nuclear fuel, may also be volatile, and the price EFH Corp. can obtain for electricity sales may not change at the same rate as changes in fuel costs. In addition, EFH Corp. purchases and sells natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting obligations.

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

• volatility in natural gas prices;

• volatility in market heat rates;

• severe or unexpected weather conditions;

• seasonality;

• changes in electricity and fuel usage;

• illiquidity in the wholesale power or other markets;

• transmission or transportation constraints, inoperability or inefficiencies;

• availability of competitively-priced alternative energy sources;

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

• changes in generation efficiency;

• outages at EFH Corp.’s generation facilities or those of 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 and 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 EFH Corp.’s generation facilities are located in the ERCOT market, a market with limited interconnections to other markets. Wholesale electricity prices in the ERCOT market generally correlate with the price of natural gas because marginal electricity demand is generally supplied by natural gas-fueled generation plants.

Wholesale electricity prices also correlate with market heat rates (a measure of efficiency of the marginal price-setting generator of electricity), which could fall if demand for electricity were to decrease or if additional generation facilities are built in ERCOT. Accordingly, the contribution to earnings and the value of EFH Corp.’s baseload (lignite/coal-fueled and nuclear) generation assets, which provided a substantial portion of EFH Corp.’s supply volumes in 2008, are dependent in significant part upon the price of natural gas and market heat rates. As a result, EFH Corp.’s baseload generation assets could significantly decrease in profitability and value if natural gas prices or market heat rates fall.

22

EFH Corp.’s 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.

EFH Corp. 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 its generation assets and the size of its position relative to market liquidity. To the extent EFH Corp. has unhedged positions, fluctuating commodity prices and/or market heat rates can materially impact its results of operations and financial position, either favorably or unfavorably.

To manage its financial exposure related to commodity price fluctuations, EFH Corp. routinely enters into contracts to hedge portions of purchase and sale commitments, weather positions, fuel requirements and inventories of natural gas, lignite, coal, crude oil, diesel fuel and refined products, and other commodities, within established risk management guidelines. As part of this strategy, EFH Corp. routinely utilizes fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Although EFH Corp. devotes 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, EFH Corp. hedges the expected needs of its wholesale and retail customers, but unexpected changes due to weather, natural disasters (such as Hurricane Ike), market constraints or other factors could cause EFH Corp. 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, EFH Corp. cannot precisely predict the impact that risk management decisions may have on its businesses, results of operations or financial position.

With the tightening of credit markets, there has been some decline in the number of market participants in the energy commodities markets, resulting in less liquidity, particularly in the ERCOT wholesale electricity market. Participation by financial institutions and other intermediaries (including investment banks) has particularly declined. Extended declines in market liquidity could materially affect EFH Corp.’s ability to hedge its financial exposure to desired levels.

To the extent it engages in hedging and risk management activities, EFH Corp. is exposed to the risk that counterparties that owe it money, energy or other commodities as a result of market transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, EFH Corp. might be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. In such event, EFH Corp. might 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 EFH Corp.

EFH Corp. may suffer material losses, costs and liabilities due to ownership and operation of the Comanche Peak nuclear generation plant.

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

• unscheduled outages or unexpected costs due to equipment, mechanical, structural 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;

• the costs of procuring nuclear fuel;

• the costs of securing the plant against possible terrorist 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.

23

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

• Operational Risk — Operations at any nuclear generation plant could degrade to the point where the plant 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 plant 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 plant 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 plants 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 EFH Corp.’s reputation. Any such resulting liability from a nuclear accident could exceed EFH Corp.’s resources, including insurance coverage.

The operation and maintenance of electricity generation and delivery facilities involves significant risks that could adversely affect EFH Corp.’s results of operations and financial condition.

The operation and maintenance of electricity generation and delivery facilities involves many risks, including, as applicable, start-up risks, breakdown or failure of facilities, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source or the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in lost revenues and/or increased expenses. A significant number of EFH Corp.’s facilities were constructed many years ago. In particular, older generating equipment and transmission and distribution equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep operating at peak efficiency or reliability. The risk of increased maintenance and capital expenditures arises from (a) increased starting and stopping of generation equipment due to the volatility of the competitive generation market, (b) any unexpected failure to generate electricity, including failure caused by breakdown or forced outage and (c) damage to facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events. Further, EFH Corp.’s 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, EFH Corp. could be subject to additional costs and/or the write-off of its investment in the project or improvement.

Insurance, warranties or performance guarantees may not cover all or any of the lost revenues or increased expenses, 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 EFH Corp.’s control.

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EFH Corp.’s cost of compliance with environmental laws and regulations and its commitments, and the cost of compliance with new environmental laws, regulations or commitments could materially adversely affect EFH Corp.’s results of operations and financial condition.

EFH Corp. is subject to extensive environmental regulation by governmental authorities. In operating its facilities, EFH Corp. is required to comply with numerous environmental laws and regulations and to obtain numerous governmental permits. EFH Corp. may incur significant additional costs beyond those currently contemplated to comply with these requirements. If EFH Corp. fails to comply with these requirements, it 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 EFH Corp. or its 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.

In conjunction with the building of three new generation units, EFH Corp. has committed to reduce emissions of mercury, NO_X and SO₂ associated with its baseload generation units so that the total of these emissions from both existing and new lignite/coal-fueled units are 20% below 2005 levels. EFH Corp. may incur significantly greater costs than those contemplated in order to achieve this commitment.

EFH Corp. has formed a Sustainable Energy Advisory Board that advises it in its pursuit of technology development opportunities that, among other things, are designed to reduce EFH Corp.’s impact on the environment. Any adoption of Sustainable Energy Advisory Board recommendations may cause EFH Corp. to incur significant costs in addition to the costs referenced above.

EFH Corp. 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 or if EFH Corp. fails to obtain, maintain or comply with any such approval, the operation and/or construction of its facilities could be stopped, curtailed or modified or become subject to additional costs.

In addition, EFH Corp. may be responsible for any on-site liabilities associated with the environmental condition of facilities that it has 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, EFH Corp. may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against EFH Corp. or fail to meet its indemnification obligations to EFH Corp.

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EFH Corp.’s financial condition and results of operations may be materially adversely affected if new federal and/or state legislation or regulations are adopted to address global climate change.

In recent years, a growing concern has emerged nationally and internationally about global climate change and how greenhouse gas emissions (GHGs), such as 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), a tax on carbon emissions (carbon-tax), incentives for the development of low-carbon technology and federal renewable portfolio standards. In addition, in April 2007, the US Supreme Court issued its decision inMassachusetts v. US Environmental Protection Agency holding that CO₂ and other GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. Some commentators believe that the possible outcome from the decision include regulation of GHG not only from motor vehicles but also from industrial sectors, including electricity generation, transmission and distribution facilities. EFH Corp. produces GHG emissions from the combustion of fossil fuels at its generation plants. EFH Corp. estimates that its generation plants produced an average of 58 million tons of CO₂ annually from 2005 to 2007. The three new lignite-fueled units currently under construction that EFH Corp. estimates will come on-line in 2009 and 2010 will generate additional CO₂ emissions. Because a substantial portion of its generation portfolio consists of lignite/coal-fueled generation plants, EFH Corp.’s financial condition and results of operations could be materially adversely 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, EFH Corp. may be required to incur material costs to reduce its GHG emissions or to procure emission allowances or credits to comply with such program. To the extent a carbon-tax is adopted, EFH Corp. could be subject to a material tax liability under such a program and could incur material costs to reduce its GHG emissions in order to reduce such tax liability.

EFH Corp.’s financial condition and results of operations may be materially adversely affected by the effects of extreme weather conditions.

EFH Corp. could be subject to the effects of extreme weather. Extreme weather conditions could stress EFH Corp.’s transmission and distribution system or its generation facilities resulting in increased maintenance and capital expenditures. Extreme weather events, including hurricanes or 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 EFH Corp. foregoing sales of electricity and lost revenue. Similarly, an extreme weather event might affect the availability of generation and transmission capacity, limiting EFH Corp.’s ability to source or deliver electricity to where it is needed. These conditions, which cannot be reliably predicted, could have an adverse consequence by requiring EFH Corp. to seek additional sources of electricity when wholesale markets are tight or to seek to sell excess electricity when those markets are weak.

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

The rates charged by Oncor are regulated by the PUCT and certain cities and are subject to cost-of-service regulation and annual earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Oncor’s rates are regulated based on an analysis of Oncor’s costs and capital structure, as reviewed and approved in a regulatory proceeding. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCT will judge all of Oncor’s costs to have been prudently incurred, that the PUCT will not reduce the amount of invested capital included in the capital structure that Oncor’s rates are based upon, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of Oncor’s costs, including regulatory assets reported in the balance sheet, and the return on invested capital allowed by the PUCT.

In June 2008, Oncor filed a general case (Docket No. 35717) for rate review with the PUCT and 204 cities. If approved as requested, this review would result in an aggregate annual rate increase of approximately $253 million. A hearing on the merits concluded in February 2009. Resolution of this proposed increase is expected to occur in summer 2009. Upon such resolution, any resulting rate changes will commence. Oncor cannot predict the outcome of this or any rate case or its effect on Oncor’s results of operations or cash flows.

In addition, in connection with the Merger, Oncor has made several commitments to the PUCT regarding its rates. For example, Oncor committed that it will, in rate cases after its 2008 general rate case through proceedings initiated prior to December 31, 2012, support a cost of debt that will be based on the then-current cost of debt of electric utilities with investment grade credit ratings equal to Oncor’s ratings as of October 1, 2007. As a result, Oncor may not be able to recover debt costs above its cost of debt prior to the Merger.

While EFH Corp. believes Oncor’s rates are just and reasonable, EFH Corp. cannot predict the results of any rate case, including the rate case filed in June 2008.

EFH Corp.’s growth strategy, including investment in three new lignite-fueled generation units and Oncor’s capital program, may not be executed as planned, which could adversely impact EFH Corp.’s financial condition and results of operations.

There can be no guarantee that the execution of EFH Corp.’s growth strategy will be successful. As discussed below, EFH Corp.’s growth strategy is dependent upon many factors. Changes in laws, regulations, markets, costs, the outcome of on-going litigation or other factors could negatively impact the execution of EFH Corp.’s growth strategy, including causing management to change the strategy. Even if EFH Corp. is able to execute its growth strategy, it may take longer than expected and costs may be higher than expected.

There can be no guarantee that the execution of the lignite-fueled generation development program will be successful. While EFH Corp. has experience in operating lignite-fueled generation facilities, it has limited recent experience in constructing, commissioning and starting-up such facilities. To the extent construction is not managed efficiently and to a timely conclusion, cost overruns may occur, resulting in the overall program costing significantly more than anticipated. This may also result in delays in the expected online dates for the facilities resulting in less overall income than projected. While EFH Corp. believes it can acquire the resources needed to effectively execute this program, it is exposed to the risk that it may not be able to attract and retain skilled labor, at projected rates, for constructing, commissioning and starting-up these new facilities.

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EFH Corp.’s lignite-fueled generation development program is subject to changes in laws, regulations and policies that are beyond its control. Changes in law, regulation or policy regarding commodity prices, power prices, electricity competition or solid-fuel generation facilities or other related matters could adversely impact this program. In recent months, global warming has received significant media attention, which has resulted in legislators focusing on environmental laws, regulations and policies. Changes in environmental law, regulation or policy, such as regulations of emissions of carbon dioxide, could adversely impact this program. Although EFH Corp. has received permits to construct and operate the new units that are a part of the lignite-fueled generation development program, some of these permits are subject to ongoing litigation. See Item 3 “Legal Proceedings — Litigation Related to Generation Facilities” for further detail regarding such ongoing litigation. An adverse ruling on these matters could materially and adversely effect the implementation of this program.

EFH Corp.’s lignite-fueled generation development program is subject to changes in the electricity market, primarily ERCOT, that are beyond its control. If demand growth is less than expected or if other generation companies build a significant amount of new generation assets in ERCOT, market prices of power could fall such that the new generation capacity becomes uneconomical. In addition, any unanticipated reduction in wholesale electricity prices, market heat rates and natural gas prices, which could occur for a variety of reasons, could adversely impact this program. Even if EFH Corp. enters into hedges to reduce such exposures, it would still be subject to the credit risk of its counterparties.

EFH Corp.’s lignite-fueled generation development program is subject to other risks that are beyond its control. For example, EFH Corp. is exposed to the risk that a change in technology for electricity generation facilities and/or emissions control technologies may make other generation facilities less costly and more attractive than EFH Corp.’s new generation facilities. EFH Corp. is subject to risks relating to transmission capabilities and constraints. EFH Corp. is also exposed to the risk that its contractors may default on their obligations and compensation for damages received, if any, will not cover its losses.

There can be no guarantee that the execution of Oncor’s capital deployment program for its electricity delivery facilities will be successful, and there can be no assurance that the capital investments Oncor intends to make in connection with its electricity delivery business will produce the desired reductions in cost and improvements to service and reliability. Furthermore, there can be no guarantee that Oncor’s capital investments, including the investment of approximately $1.3 billion (based on ERCOT cost estimates for CREZ construction projects) to construct CREZ-related transmission lines and facilities pursuant to the construction assignment awarded to Oncor at a January 2009 PUCT open meeting, will ultimately be recoverable through rates or, if recovered, that they will be recovered on a timely basis.

Ongoing performance improvement initiatives may not achieve desired cost reductions and may instead result in significant additional costs if unsuccessful. In addition, EFH Corp. may incur significant transition costs and/or experience significant operational disruptions in connection with the termination of its outsourcing arrangement with Capgemini.

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 EFH Corp.’s 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 EFH Corp.’s business and financial prospects. For example, EFH Corp. is in the process of upgrading or replacing certain of its software systems, most notably is the transition of its retail customer care and revenue management software systems to a new SAP software platform. Such transition could result in material disruptions to EFH Corp.’s operations. Disruptions in retail customer care operations could result in decreased revenue should the number of customers decline due to customer dissatisfaction. Disruptions in retail revenue management operations could result in decreased revenue or delayed or lost cash flows to the extent such disruptions result in billing errors or the inability to bill or collect payments for an extended period of time.

In addition, EFH Corp. may incur significant transition costs or experience significant operational disruptions in connection with the termination of its outsourcing arrangement with Capgemini as it transitions the business support services back to EFH Corp. or to other vendors. Such additional costs and/or operational difficulties could have an adverse effect on EFH Corp.’s business and financial prospects. Moreover, EFH Corp. is subject to the risk that any new outsourcing arrangements for such business support services may not produce the desired cost savings.

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TXU Energy’s retail business is subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to its reputation and/or the results of operations of the retail business.

TXU Energy’s 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. TXU Energy’s 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 TXU Energy’s retail business may be adversely affected, customer confidence may be diminished, or TXU Energy’s 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/or results of operations.

TXU Energy relies 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 its business and results of operations.

TXU Energy depends 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, TXU Energy’s ability to sell and deliver electricity may be hindered, it may have to forgo sales or it may have to 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 TXU Energy has 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 TXU Energy’s customers could negatively impact the satisfaction of its customers with its service.

TXU Energy offers bundled services to its retail customers, with some bundled services offered at fixed prices and for fixed terms. If TXU Energy’s costs for these bundled services exceed the prices paid by its customers, its results of operations could be materially adversely affected.

TXU Energy offers its customers a bundle of services that include, at a minimum, electricity plus transmission, distribution and related services. The prices TXU Energy charges for its 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 TXU Energy’s underlying cost to provide the components of such services.

TXU Energy’s retail business is subject to the risk that it will not be able to profitably serve its customers given its previously announced price cuts and price protection, which could result in an adverse impact to its reputation and/or results of operations.

TXU Energy committed in 2006 to not increase prices above then current levels through 2009 for qualifying residential customers who remain on certain plans with rates that were then equal to the formerly regulated rate. The prices TXU Energy charges during this period could fall below TXU Energy’s underlying cost to provide electricity.

TXU Energy’s REP certification is subject to PUCT review.

The PUCT may at any time initiate an investigation into whether TXU Energy is compliant with PUCT Substantive Rules and whether it has met all of the requirements for REP certification, including financial requirements. Any removal or revocation of a REP certification would mean that TXU Energy would no longer be allowed to provide electricity service to retail customers. Such decertification would have an adverse effect on TXU Energy and its financial prospects. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulations and Rates” regarding a proposed rule replacement.

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Changes in technology may reduce the value of EFH Corp.’s generation plants and/or Oncor’s electricity delivery facilities and may significantly impact EFH Corp.’s 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 the traditional generation plants owned by Luminant. While demand for electric energy services is generally increasing throughout the US, the rate of construction and development of new, more efficient generation facilities may exceed increases in demand in some regional electric markets. Consequently, where EFH Corp. has facilities, the profitability and market value of its generation assets could be significantly reduced. Also, electricity demand could be reduced by increased conservation efforts and advances in technology, which could likewise significantly reduce the value of EFH Corp.’s generation assets and electricity delivery facilities. 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, EFH Corp.’s revenues could be reduced.

EFH Corp.’s 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 zones at or near wind generation development, especially in, but not exclusive to, the ERCOT West zone where most of the new wind power generation is located. As a result, the profitability of EFH Corp.’s generation facilities and power purchase contracts, including certain wind generation power purchase contracts, has been impacted by the effects of the wind power generation, and the value could significantly decrease if wind power generation has a material sustained effect on market heat rates.

EFH Corp.’s revenues and results of operations may be adversely impacted as ERCOT transitions the current zonal market structure to a nodal wholesale market.

Substantially all of EFH Corp.’s competitive businesses are located in the ERCOT market, which is currently in the process of transitioning from a zonal market structure with four Congestion Management Zones to a nodal market structure that will directly manage congestion on a localized basis. In a nodal market, the prices received and paid for power will be based on pricing determined at specific interconnection points on the transmission grid (i.e., Locational Marginal Pricing), which could result in lower revenues or higher costs for EFH Corp.’s competitive businesses. This market structure change could have a significant impact on the profitability and value of EFH Corp.’s competitive businesses depending on how the Locational Marginal Pricing develops.

EFH Corp.’s future results of operations may be negatively impacted by settlement adjustments determined by ERCOT related to prior periods.

ERCOT is the independent system operator that is responsible for maintaining reliable operation of the bulk electric power supply system in the ERCOT market. Its responsibilities include the clearing and settlement of electricity volumes and related ancillary services among the various participants in the deregulated Texas market. Settlement information is due from ERCOT within two months after the operating day, and true-up settlements are due from ERCOT within six months after the operating day. Likewise, ERCOT has the ability to resettle any operating day at any time after the six month settlement period, usually the result of a lingering dispute, an alternative dispute resolution process or litigated event. As a result, EFH Corp. is subject to settlement adjustments from ERCOT related to prior periods, which may result in charges or credits impacting EFH Corp.’s future reported results of operations.

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

EFH Corp. derives substantially all of its 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 EFH Corp.’s results of operations and financial condition.

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

Downgrades in EFH Corp.’s or any of its applicable subsidiaries’ long-term debt ratings generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease and might trigger liquidity demands pursuant to the terms of new commodity contracts, leases or other agreements. In connection with the Merger, Fitch, Moody’s and S&P downgraded EFH Corp.’s and TCEH’s long term debt ratings, and in November 2008, Moody’s changed the rating outlook for EFH Corp. and TCEH to negative from stable, primarily due to elections by EFH Corp. and TCEH to exercise the “payment-in-kind” (PIK) interest payment option on their respective senior toggle notes.

Most of EFH Corp.’s large customers, suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions. If EFH Corp.’s (or an applicable 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-related instruments, or counterparties could decline to do business with EFH Corp (or its applicable subsidiary).

The global financial crisis has caused unprecedented market volatility and may have impacts on EFH Corp.’s business and financial condition that EFH Corp. currently cannot predict.

Because its operations are capital intensive, EFH Corp. expects to rely over the long-term upon access to financial markets (particularly the attainment of liquidity facilities) as a significant source of liquidity for capital requirements not satisfied by cash-on-hand, operating cash flows or its revolving credit facilities. The capital and credit markets have been experiencing extreme volatility and disruption. As a result, the continued credit crisis and related turmoil in the global financial system may have an impact on EFH Corp.’s business and financial condition. EFH Corp.’s ability to access the capital or credit markets may be severely restricted at a time when EFH Corp. would like, or needs, to access those markets, which could have an impact on EFH Corp.’s flexibility to react to changing economic and business conditions. In addition, the cost of debt financing may be materially adversely impacted by these market conditions. As such, there can be no assurance that the capital and credit markets will continue to be a reliable or acceptable source of short-term or long-term financing for EFH Corp. If current levels of market disruption and volatility continue or worsen, EFH Corp. may be forced to meet its liquidity needs, such as its anticipated capital expenditures, through its cash flows. Additionally, the crisis could have a broader impact on business in general in ways that could lead to reduced electricity usage, which could have a negative impact on EFH Corp.’s revenues, and the credit crisis could have an impact on EFH Corp.’s customers, counterparties and/or lenders, causing them to fail to meet their obligations to EFH Corp.

EFH Corp.’s 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 adversely affect results of operations and/or financial condition.

EFH Corp.’s businesses are capital intensive. EFH Corp. and its subsidiaries rely on access to financial markets and liquidity facilities as a significant source of liquidity for capital requirements not satisfied by cash-on-hand or operating cash flows. The inability to raise capital on favorable terms or access liquidity facilities, particularly during times of uncertainty similar to that which is currently being experienced in the financial markets, could impact EFH Corp.’s ability to sustain and grow its businesses and would likely increase capital costs. EFH Corp.’s 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 of EFH Corp.’s credit or the credit of its subsidiaries or a reduction in EFH Corp.’s or its applicable subsidiaries’ credit ratings;

• a deterioration of the credit or bankruptcy of one or more lenders or counterparties under EFH Corp.’s or its applicable subsidiaries’ liquidity facilities that affects the ability of such lender(s) to make loans to EFH Corp. or its subsidiaries;

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

• a material breakdown in EFH Corp.’s risk management procedures, and

• the occurrence of changes in EFH Corp.’s businesses that restrict its ability to access liquidity facilities.

31

Although EFH Corp. expects to actively manage the liquidity exposure of existing and future hedging arrangements, given the size of the long-term hedging program, any significant increase in the price of natural gas could result in EFH Corp. being required to provide cash or letter of credit collateral in substantial amounts. While these potential posting obligations are primarily supported by the 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 EFH Corp.’s credit quality could result in clearing agents or other counterparties requesting additional collateral. EFH Corp. has potential credit concentration risk related to the limited number of lenders that provide EFH Corp. liquidity to support its hedging program. A deterioration of the credit quality of such lenders could materially affect EFH Corp.’s ability to continue such program on acceptable terms. An event of default by one or more of EFH Corp.’s hedge counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if EFH Corp. owes amounts related to its commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to EFH Corp.

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

In the event EFH Corp.’s liquidity facilities are being used largely to support the long-term hedging program as a result of a significant increase in the price of natural gas or significant reduction in credit quality, EFH Corp. may have to forego certain capital expenditures or other investments in its competitive businesses or other business opportunities.

Further, a lack of available liquidity could adversely impact the evaluation of EFH Corp.’s 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 long-term hedging program.

The costs of providing pension and other postretirement employee benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on EFH Corp.’s results of operations 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 eligible employees and their eligible dependents upon the retirement of such employees from EFH Corp. EFH Corp.’s costs of providing such benefits and related funding requirements are dependent upon numerous factors, assumptions and estimates and are subject to changes in such factors, assumptions and estimates, including the market value of the assets funding its pension plan and its 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 recent substantial dislocation in the financial markets has caused the value of the investments that fund EFH Corp.’s pension and OPEB plans to significantly differ from, and may alter the values and actuarial assumptions EFH Corp. uses to calculate, its projected future pension plan expense and OPEB costs. A continuation or further decline in the value of these investments could increase the expenses of EFH Corp.’s pension plan and the costs of its OPEB plan and related funding requirements in the future. EFH Corp.’s 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.

32

As was the case in the fourth quarter 2008 (as discussed in Notes 1 and 3 to Financial Statements), goodwill and/or other intangible assets not subject to amortization that EFH Corp. has recorded in connection with the Merger are subject to at least annual impairment evaluations and as a result, EFH Corp. could be required to write off some or all of this goodwill and other intangible assets, which may reflect adverse impacts on EFH Corp.’s financial condition and results of operations.

In accordance with SFAS 142, 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. 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 adverse impact on EFH Corp.’s reported results of operations and financial position.

The loss of the services of EFH Corp.’s key management and personnel could adversely affect EFH Corp.’s ability to operate its businesses.

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

The Sponsor Group controls and may have conflicts of interest with EFH Corp. in the future.

The Sponsor Group indirectly owns approximately 60% of EFH Corp.’s capital stock on a fully-diluted basis through their investment in Texas Holdings. As a result of this ownership and the Sponsor Group’s ownership in interests of the general partner of Texas Holdings, the Sponsor Group has control over decisions regarding EFH Corp.’s 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 stockholders.

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 EFH Corp. Members of the Sponsor Group may also pursue acquisition opportunities that may be complementary to EFH Corp.’s businesses and, as a result, those acquisition opportunities may not be available to EFH Corp. 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 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 EFH Corp.’s decisions.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

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Item 3. LEGAL PROCEEDINGS

Litigation Related to the Merger

Two putative class and derivative lawsuits and one derivative lawsuit were filed in the US District Court, Northern District of Texas, Dallas Division in March 2007 against the former directors of EFH Corp., EFH Corp. (then known as TXU Corp.), as a nominal defendant, and the Sponsor Group arising out of the Merger Agreement. In April 2007, the Plaintiffs filed Amended Complaints asserting only derivative claims against the same defendants. The lawsuits sought to enjoin the Merger Agreement. The cases alleged that the former directors violated various fiduciary duties by approving the Merger Agreement and the Sponsor Group aided and abetted that alleged conduct. The Plaintiffs contended that the former directors violated fiduciary duties owed to shareholders by failing to maximize the value of EFH Corp. and by breaching duties of loyalty and due care by not taking adequate measures to ensure that the interests of shareholders were properly protected. EFH Corp. and its former directors filed Motions to Dismiss based on the Plaintiffs’ failure to comply with the provisions of the Texas Business Organizations Code (TBOC) applicable to filing and pursuing derivative proceedings. As described below, these lawsuits were dismissed in May 2008.

In February and March 2007, three derivative lawsuits were filed in Dallas County state district courts arising out of the Merger Agreement. The suits, filed by putative shareholders, alleged that EFH Corp.’s former directors, named as defendants, breached fiduciary duties owed EFH Corp. by approving the Merger Agreement. The petitions were consolidated into one action in the 44^th District Court, Dallas County, Texas, and included claims that the defendants failed to ensure that the Merger was in the best interest of EFH Corp., that the former directors participated in the Merger where their loyalties were divided and where they were to receive a personal financial benefit, that such alleged conduct constituted a breach of their duties of care, loyalty, good faith, candor and independence owed to EFH Corp., and that the Sponsor Group aided and abetted the alleged breaches of fiduciary duties by the directors. As described below, these lawsuits were dismissed in April 2008.

In February and March 2007, eight lawsuits were filed in state district court in Dallas County, Texas by putative shareholders against the former directors of EFH Corp., EFH Corp. (then known as TXU Corp.), the Sponsor Group, and certain financial entities, asserting claims on behalf of former owners of shares of EFH Corp. common stock as well as seeking to certify a class action on behalf of allegedly similarly situated shareholders. The lawsuits, which were consolidated into one action in the 44^th District Court, Dallas County, Texas, contended that the former directors of EFH Corp. violated various fiduciary duties owed plaintiffs and other shareholders in connection with the execution of the Merger Agreement and that the Sponsor Group and certain financial entities aided and abetted the alleged breaches of fiduciary duties by the former directors. Plaintiffs sought to enjoin defendants from consummating the Merger Agreement until such time as a procedure or process was adopted to obtain the highest possible price for shareholders, and requested that the Court direct the preclosing officers and directors of EFH Corp. to exercise their fiduciary duties in order to obtain a transaction in the best interest of EFH Corp. shareholders. The consolidated suit included claims that the former directors failed to take steps to properly value or maximize the value of EFH Corp. and breached their duties of loyalty, good faith, candor and independence owed to former EFH Corp. shareholders. EFH Corp. and its former directors filed a Motion to Dismiss and in May 2007, the Court granted the Motion and dismissed the consolidated putative class action suit with prejudice. In May 2007, Plaintiffs moved for reconsideration of the order dismissing the action; however, Plaintiffs subsequently withdrew this motion. As described below, these lawsuits were dismissed in April 2008.

34

In July 2007, a putative class action lawsuit was filed in the US District Court, Northern District of Texas, Dallas Division by a putative shareholder against EFH Corp. (then known as TXU Corp.) and its former directors asserting a claim under Section 14(a) of the Securities Exchange Act of 1934 and the rules and regulations thereunder, asserting that the preliminary proxy statement of EFH Corp. filed in June 2007 failed to adequately describe the relevant facts and circumstances regarding the Merger as well as seeking to certify the litigation as a class action on behalf of allegedly similarly situated shareholders. In July 2007, the Sponsor Group, joined by EFH Corp. entered into a memorandum of understanding with plaintiffs that resulted in the dismissal of this litigation as described below.

In July 2007, the Sponsor Group, joined by EFH Corp. for the limited purpose described below, executed a memorandum of understanding with the plaintiffs in certain of the lawsuits described above pursuant to which, when approved by the court in which the litigation was pending, to the extent required, all of the litigation related to the Merger described above was dismissed with prejudice. None of EFH Corp.’s former directors agreed to fund any payment or pay any other consideration under the settlement. EFH Corp. did agree to make certain revisions to the final proxy statement related to the approval of the Merger as part of the agreement between the Sponsor Group and the plaintiffs to settle the litigation and agreed that under certain circumstances the termination fee payable by EFH Corp. under the Merger Agreement would be $925 million rather than $1 billion. In addition, by reasons of the closing of the Merger, EFH Corp. merged with the entity obligated to fund any court approved attorneys’ fees. Accordingly, EFH Corp. was legally obligated for such payment. In January 2008, a final settlement agreement was executed by the plaintiffs in the above described litigation matters related to the Merger. The settlement was approved and a Final Order and Judgment was entered dismissing with prejudice all litigation pending in the State District Court in April 2008. The settlement was approved and a Final Order and Judgment was entered into by the US District Court in May 2008, dismissing with prejudice all claims related to the Merger against EFH Corp. and its preclosing officers and directors. In June 2008, an objector appealed the Final Order and Judgment of the US District Court to the US Court of Appeals for the Fifth Circuit. In November 2008, the appeal was denied.

Litigation Related to Generation Development

An administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas to a subsidiary of EFH Corp. was filed in September 2007 in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. The TCEQ has filed the administrative record with the District Court. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. One of the plaintiffs has asked the court to consolidate all these proceedings, and the Attorney General of Texas, on behalf of TCEQ, has filed pleas to the jurisdiction that would, if granted, dismiss all but the administrative appeal. EFH Corp. does not know when the court will rule on these requests. EFH Corp. believes the Oak Grove air permit granted by the TCEQ is protective of the environment and that the application for and the processing of the air permit by the TCEQ was in accordance with law. There can be no assurance that the outcome of these matters would not result in an adverse impact on the Oak Grove project.

35

In December 2006, a lawsuit was filed in the US District Court for the Western District of Texas against Luminant Generation Company LLC (then known as TXU Generation Company LP), Oak Grove Management Company LLC (both indirect wholly-owned subsidiaries of EFH Corp.) and EFH Corp. (then known as TXU Corp.). The complaint sought declaratory and injunctive relief, as well as the assessment of civil penalties, with respect to the permit application for the construction and operation of the Oak Grove generation facility in Robertson County, Texas. The plaintiffs alleged violations of the Federal Clean Air Act, Texas Health and Safety Code and Texas Administrative Code and sought to temporarily and permanently enjoin the construction and operation of the Oak Grove generation plant. The complaint also asserted that the permit application was deficient in failing to comply with various modeling and analyses requirements relative to the impact of emissions from the Oak Grove plant. Plaintiffs further requested that the District Court enter an order requiring the defendants to take other appropriate actions to remedy, mitigate and offset alleged harm to the public health and environment. EFH Corp. believes the Oak Grove air permit granted by the TCEQ in June 2007 is protective of the environment and that the application for and the processing of the air permit by Oak Grove Management Company LLC with the TCEQ has been in accordance with applicable law. EFH Corp. and the other defendants filed a Motion to Dismiss the litigation, which was granted by the District Court in May 2007. The plaintiffs appealed the District Court’s dismissal of the case to the US Fifth Circuit Court of Appeals, and in July 2008, the US Fifth Circuit Court of Appeals upheld the District Court’s dismissal of the case. The plaintiffs appealed that decision by the US Fifth Circuit Court of Appeals to the US Supreme Court, and in December 2008, the US Supreme Court denied the plaintiffs’ petition for review. Accordingly, this litigation has concluded favorably to EFH Corp.

In May 2008, the Sierra Club announced that it may sue Oak Grove Management Company LLC for violating federal Clean Air Act provisions regarding hazardous air pollutants. Similarly, in July 2008, the Sierra Club announced that it may sue Luminant, after the expiration of a 60-day waiting period, for violating federal Clean Air Act provisions in connection with its Martin Lake generation facility. In December 2008, Luminant reached a settlement with the Sierra Club regarding its allegations relating to Oak Grove. Pursuant to the settlement, Luminant has filed for a Maximum Achievable Control Technology determination for hazardous air pollutant emissions by the TCEQ and has agreed to offset any emissions above the levels set in that review; in exchange the Sierra Club will not pursue legal action to obstruct construction or commencement of operation of the Oak Grove units. EFH Corp. cannot predict whether the Sierra Club will actually file suit relating to Martin Lake or the outcome of any such proceeding.

In September 2007, a subsidiary of EFH Corp. acquired from Alcoa Inc. the air permit related to the Sandow 5 facility that had been previously issued by the TCEQ. Although a federal district court approved a settlement pursuant to which EFH Corp. acquired the permit, environmental groups opposed to the settlement appealed the district court’s decision to the US Fifth Circuit Court of Appeals. In June 2008, the US Fifth Circuit Court of Appeals upheld the district court’s decision. The time period for the environmental groups to petition the US Supreme Court for review elapsed without any such petition being filed. Accordingly, this litigation has concluded favorably to EFH Corp.

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Other Litigation

In September 2005, a lawsuit was filed in the US District Court for the Northern District of Texas, Dallas Division against EFH Corp. (then known as TXU Corp.) and C. John Wilder, EFH Corp.’s former Chief Executive Officer. The plaintiffs’ Amended Complaint asserts claims on behalf of the plaintiffs and a putative class of owners of certain EFH Corp. securities who tendered such securities in connection with a tender offer conducted by EFH Corp. in 2004. The Amended Complaint alleges violations of the provisions of Sections 14(e), 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 thereunder. The allegations relate to a tender offer conducted in September and October 2004 for certain equity-linked securities in which it was expressly disclosed that EFH Corp. management was evaluating whether it should recommend to the board of directors that the board reevaluate EFH Corp.’s dividend policy. After the tender offer was closed, and consistent with the disclosure, management did make a recommendation to the board to reevaluate the dividend policy, and the board elected to increase the quarterly dividend. The plaintiffs contend that such disclosure in connection with the tender offer was inadequate. EFH Corp. maintains that the disclosure provided in connection with the tender offer regarding the evaluation of the dividend policy was complete and accurate at the time the tender offer was initiated as well as when it was closed. A Motion to Dismiss was filed by the defendants, and the District Court entered an order granting the Motion to Dismiss and dismissing this litigation with prejudice in August 2006. The plaintiffs filed a timely notice of appeal, and on appeal, the US Court of Appeals for the Fifth Circuit remanded the dismissal to the District Court in light of the decisions in Tellabs, Inc. v. Makor Issues & Rights, Ltd. On remand, plaintiffs filed a Second Amended Complaint, and defendants filed a Motion to Dismiss. The District Court entered an order granting the Motion to Dismiss and dismissing this litigation with prejudice in April 2008. The plaintiffs filed a timely notice of appeal in May 2008 and the appeal is currently pending before the US Court of Appeals for the Fifth Circuit. Oral argument was held in February 2009, and EFH Corp. is now awaiting a ruling from the US Court of Appeals for the Fifth Circuit. While EFH Corp. is unable to estimate any possible loss or predict the outcome of this litigation, EFH Corp. believes the claims made in this litigation are without merit and, accordingly, intends to vigorously defend the appeal.

In July 2008, Alcoa Inc. filed a lawsuit in Milam County, Texas district court against Luminant Generation Company LLC, Luminant Mining Company LLC, Sandow Power Company LLC, Luminant Energy Company LLC and EFH Corp. The lawsuit makes various claims concerning operation of the Sandow Unit 4 generation facility and the Three Oaks lignite mine and construction of the Sandow 5 unit, including claims for breach of contract, breach of fiduciary duty, fraud and conversion, and requests money damages in an unspecified amount, declaratory judgment, an accounting and rescission. A federal district court in Austin, Texas has ordered Alcoa Inc. to amend its Milam County complaint to remove any references to a federal consent decree relating to Sandow Units 4 and 5. Alcoa Inc. has not yet filed its amended complaint. While EFH Corp. is unable to estimate any possible loss or predict the outcome of this litigation, EFH Corp. believes the claims made in this litigation are without merit and, accordingly, intends to vigorously defend this litigation.

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Regulatory Investigations and Reviews

In March 2007, the PUCT issued a Notice of Violation (NOV) stating that the PUCT staff was recommending an enforcement action, including the assessment of administrative penalties, against EFH Corp. and certain affiliates for alleged market power abuse by its power generation affiliates and Luminant Energy in ERCOT-administered balancing energy auctions during certain periods of the summer of 2005. In September 2007, the PUCT issued a revised NOV in which the proposed administrative penalty amount was reduced from $210 million to $171 million. The revised NOV was necessary, according to the PUCT staff, to correct calculation errors in the initial NOV. As revised, the NOV was premised upon the PUCT staff’s allegation that Luminant Energy’s bidding behavior was not competitive and increased market participants’ costs of balancing energy by approximately $57 million, including approximately $19 million in incremental revenues to EFH Corp. In November 2008, representatives of the parties to the NOV proceeding entered into a Settlement Agreement as a means of fully resolving all matters related to the NOV. Among other things, the Settlement Agreement provides for payment by Luminant of an administrative penalty of $15 million to the PUCT and acknowledgment from the PUCT staff that Luminant’s Voluntary Mitigation Plan (VMP), which was filed with the PUCT in July 2007, continues to represent an appropriate safe harbor for Luminant from future enforcement actions for activities covered by the VMP. In addition, the PUCT staff agreed that neither the payment of the penalty amount by Luminant nor anything in the Settlement Agreement should be construed as an admission of liability by Luminant. Luminant expressly denied such liability in the Settlement Agreement. The Settlement Agreement was approved by the PUCT in December 2008, and the $15 million was paid to the PUCT in January 2009.

In June 2008, the EPA issued a request for information to Luminant Energy under 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. EFH Corp. is cooperating with the EPA and is responding in good faith to the EPA’s request. EFH Corp. is unable to predict the outcome of this matter.

Other Proceedings

In addition to the above, EFH Corp. is involved in various other legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on its financial position, results of operations or cash flows.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

In December 2008, Tom Ferguson was elected as a director of EFH Corp. by unanimous written consent of the shareholders of EFH Corp. as a replacement for William Young.

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PART II

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

As a result of the Merger, EFH Corp.’s common stock is privately held, and there is no established public trading market for EFH Corp.’s common stock.

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Financial Condition— Liquidity and Capital Resources— Covenants and Restrictions Under Financing Arrangements” for a description of the restrictions on EFH Corp.’s ability to pay dividends.

The number of holders of the common stock of EFH Corp. as of February 27, 2009 was 118.

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Item 6. SELECTED FINANCIAL DATA

EFH CORP. AND SUBSIDIARIES

SELECTED FINANCIAL DATA

(millions of dollars, except ratios)

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31,
										2006			2005			2004
Operating revenues (a)	$	11,364		$	1,994		$	8,044		$	10,703		$	10,826		$	9,319
Income (loss) from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles	$	(9,838	)	$	(1,361	)	$	699		$	2,465		$	1,775		$	81
Income from discontinued operations, net of tax effect	$	—		$	1		$	24		$	87		$	5		$	378
Extraordinary gain (loss), net of tax effect	$	—		$	—		$	—		$	—		$	(50	)	$	16
Cumulative effect of changes in accounting principles, net of tax effect	$	—		$	—		$	—		$	—		$	(8	)	$	10
Exchangeable preferred membership interest buyback premium	$	—		$	—		$	—		$	—		$	—		$	849
Preference stock dividends	$	—		$	—		$	—		$	—		$	10		$	22
Net income (loss) available for common stock	$	(9,838	)	$	(1,360	)	$	723		$	2,552		$	1,712		$	(386	)
Ratio of earnings to fixed charges (b)		—			—			2.30			5.11			3.80			1.16
Ratio of earnings to combined fixed charges and preference dividends (b)		—			—			2.30			5.11			3.74			1.11
Embedded interest cost on long-term debt — end of period (c)		9.2	%		9.5	%		6.5	%		6.6	%		6.3	%		6.0	%
Embedded dividend cost on preferred stock of subsidiaries — end of period (d)		—	%		—	%		—	%		—	%		—	%		4.4	%
Capital expenditures, including nuclear fuel	$	2,978		$	707		$	2,395		$	2,297		$	1,104		$	999

See Notes to Financial Statements.

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EFH CORP. AND SUBSIDIARIES

SELECTED FINANCIAL DATA (CONTINUED)

(millions of dollars, except ratios)

	Successor						Predecessor
	December 31,						December 31,
	2008			2007			2006			2005			2004
Total assets — end of year (e)	$	59,263		$	64,804		$	27,216		$	27,978		$	24,059
Property, plant & equipment — net — end of year	$	29,522		$	28,650		$	18,569		$	17,006		$	16,495
Goodwill and intangible assets — end of year	$	17,379		$	27,319		$	729		$	728		$	723
Capitalization — end of year
Equity-linked debt securities	$	—		$	—		$	—		$	179		$	285
All other long-term debt, less amounts due currently		40,838			38,603			10,631			11,153			12,127
Preferred stock of subsidiaries (not subject to mandatory redemption) (f)		—			—			—			—			38
Preference stock		—			—			—			—			300
Common stock equity		(3,532	)		6,685			2,140			475			339
Total	$	37,306		$	45,288		$	12,771		$	11,807		$	13,089
Capitalization ratios — end of year
Equity-linked debt securities		—	%		—	%		—	%		1.5	%		2.2	%
All other long-term debt, less amounts due currently		109.5			85.2			83.2			94.5			92.6
Preferred stock of subsidiaries (f)		—			—			—			—			0.3
Preference stock		—			—			—			—			2.3
Common stock equity		(9.5	)		14.8			16.8			4.0			2.6
Total		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
Short-term borrowings – end of year	$	1,237		$	1,718		$	1,491		$	798		$	210
Long-term debt due currently – end of year	$	385		$	513		$	485		$	1,250		$	229

(a) The operating revenues shown above reflect the change in classification for commodity hedging and trading activities discussed in Note 1 to the Financial Statements that resulted in an increase in operating revenues of $1.492 billion and $554 million for the Successor period from October 11 through December 31, 2007 and the Predecessor period from January 1 through October 10, 2007, respectively, a decrease of $153 million for the year ended December 31, 2006, and an increase of $164 million and $103 million for the years ended December 31, 2005 and 2004, respectively.

(b) Fixed charges and combined fixed charges and preference dividends exceeded earnings by $10.309 billion and $2.034 billion for the year ended December 31, 2008 and for the period from October 11, 2007 through December 31, 2007, respectively.

(c) Represents the annual interest using year-end rates for variable rate debt and reflecting the effects of interest rate swaps (excluding unrealized mark-to-market gains or losses) and amortization of any discounts, premiums, issuance costs and any deferred gains/losses on reacquisitions divided by the carrying value of the debt plus or minus the unamortized balance of any discounts, premiums, issuance costs and gains/losses on reacquisitions at the end of the year.

(d) Includes the unamortized balance of the loss on reacquired preferred stock and associated amortization.

(e) The total assets shown above reflect the change in presentation related to EFH Corp.’s adoption of FSP FIN 39-1 as discussed in Note 1 to the Financial Statements. Such change in presentation resulted in an increase of $1.020 billion, $1.383 billion, $2.439 billion and $870 million in EFH Corp.’s total assets and total liabilities as of December 31, 2007, 2006, 2005 and 2004, respectively, as compared to amounts reported in the 2007 Form 10-K.

(f) Preferred stock outstanding at the end of 2008, 2007, 2006 and 2005 has a stated amount of $51 thousand.

Note: Although EFH Corp. continued as the same legal entity after the Merger, its “Selected Financial Data” for periods preceding the Merger and for the periods succeeding the Merger are presented as the consolidated financial statements of the “Predecessor” and the “Successor”, respectively. The consolidated financial statements of the Predecessor have been prepared on the same basis as the audited financial statements included in EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2007 with the exception of a change in presentation related to EFH Corp.’s adoption of FSP FIN 39-1 and a change in classification to report the results of commodity hedging and trading activities on a separate line in the income statement instead of within operating revenues. (See Note 1 to the Financial Statements “Basis of Presentation.”) The consolidated financial statements of the Successor also reflect the application of “purchase accounting.”

Note: Results for 2008 are significantly impacted by impairment charges related to goodwill, trade name and emission allowances intangible assets and natural gas-fueled generation fleet. Results for 2004 are significantly impacted by charges related to EFH Corp.’s comprehensive restructuring plan.

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Quarterly Information

Results of operations by quarter are summarized below. In the opinion of EFH Corp., 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.

	Successor
	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
2008:
Operating revenues	$	2,354		$	2,951		$	3,695	$	2,364
Net income (loss)	$	(1,269	)	$	(3,331	)	$	3,617	$	(8,855	)

	Predecessor (a)							Successor
	First Quarter			Second Quarter		Third Quarter		Period from October 11, 2007 through December 31, 2007
2007:
Operating revenues	$	2,355		$	2,405	$	2,983	$	1,994
Income (loss) from continuing operations		(497	)		110		979		(1,361	)
Income from discontinued operations, net of tax effect		—			11		13		1
Net income (loss)	$	(497	)	$	121	$	992	$	(1,360	)

(a) The 10-day period ended October 10, 2007 has not been presented as it is deemed to be immaterial.

Reconciliation of Previously Reported Quarterly Information — The following tables present changes to previously reported quarterly results, reflecting the change in classification to report the results of commodity hedging and trading activities on a separate line item in the income statement instead of within operating revenues. Income (loss) from continuing operations, income from discontinued operations, and net income (loss) available for common stock were not affected by this change (see Note 1 to the Financial Statements for additional information).

	Successor
	First Quarter
2008:
Previously reported operating revenues	$	787
Change in classification		1,567
Operating revenues	$	2,354

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	Predecessor							Successor
	First Quarter		Second Quarter		Third Quarter			Period from October 11, 2007 through December 31, 2007
2007:
Previously reported operating revenues	$	1,669	$	2,022	$	3,445		$	502
Change in classification		686		383		(462	)		1,492
Operating revenues	$	2,355	$	2,405	$	2,983		$	1,994

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of EFH Corp.’s financial condition and results of operations for the fiscal years ended December 31, 2008, 2007 and 2006 should be read in conjunction with Selected Financial Data and EFH Corp.’s audited consolidated financial statements and the notes to those statements.

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

BUSINESS

EFH Corp., a Texas corporation, is a Dallas-based holding company conducting its operations principally through its TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. Various “ring-fencing” measures have been taken to further separate Oncor from the other EFH Corp. businesses. See Note 1 to Financial Statements for a description of the material features of these “ring-fencing” measures and Note 18 to Financial Statements for discussion of minority interests sold by Oncor.

Operating Segments

EFH Corp. has aligned and reports its business activities as two operating segments: the Competitive Electric segment and the Regulated Delivery segment.

The Competitive Electric segment includes the activities of TCEH, as described above, as well as equipment salvage and resale activities related to the 2007 suspension and subsequent cancellation of the development of eight new coal-fueled generation units.

The Regulated Delivery segment includes the activities of Oncor, as described above, its wholly-owned bankruptcy-remote financing subsidiary and certain 2007 revenues and costs associated with installation of equipment that will facilitate Oncor’s technology initiatives designed to improve system reliability.

See Note 27 to Financial Statements for further information regarding reportable business segments.

EXECUTIVE SUMMARY

In October 2007, EFH Corp. completed the Merger. As a result of the Merger, EFH Corp. became a subsidiary of Texas Holdings, which is controlled by the Sponsor Group.

EFH Corp.’s consolidated net loss from continuing operations (an after-tax measure) for 2008 totaled $9.8 billion. The loss in the Competitive Electric segment totaled $8.9 billion, which primarily reflected non-cash impairments of goodwill, trade name and environmental allowances intangible assets and natural gas-fueled generation assets; interest expense on Merger-related debt; unrealized mark-to-market net losses on interest rate hedging transactions, and the effects of purchase accounting, partially offset by unrealized mark-to-market net gains on commodity positions in the long-term hedging program. The loss in the Regulated Delivery segment totaled $486 million, which primarily reflected a non-cash goodwill impairment. Corporate and Other net expenses totaled $423 million, which primarily reflected interest expense on Merger-related debt. See Results of Operations for further discussion.

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Significant Activities and Events

Effects of Declines in Financial Markets—The financial market conditions had a significant effect on EFH Corp.’s assessment of the carrying value of goodwill. EFH Corp. recorded a goodwill impairment charge of $8.860 billion in 2008, primarily arising from the dislocation in the capital markets that has increased interest rate spreads and the resulting discount rates used in estimating fair values and the effects of recent declines in market values of debt and equity securities of comparable companies. This and other non-cash impairments referenced below will not cause EFH Corp. or its subsidiaries to be in default under any of their respective debt covenants or impact counterparty trading agreements or have a material impact on liquidity.

Further, in light of the significant dislocation and continued uncertainty in the financial markets, EFH Corp. took actions to secure its available liquidity by drawing on its credit facilities and exercising the “payment-in-kind” (PIK) option on certain of its debt securities. In September 2008, EFH Corp. also terminated its wholesale energy market transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy, resulting in a charge to reserve for the direct net financial position totaling $26 million (excluding termination related costs) with respect to the transactions.

See Note 3 to Financial Statements and “Application of Critical Accounting Policies” below for more information on the goodwill and related impairment charges, Note 13 to Financial Statements regarding the charge related to Lehman Brothers Holdings Inc. and “Liquidity and Capital Resources” below for discussion of actions taken in response to the uncertain financial markets and the effect of financial market conditions on the energy commodity markets.

Long-Term Hedging Program— EFH Corp. has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, subsidiaries of EFH Corp. have entered into market transactions involving natural gas-related financial instruments. As of January 30, 2009, these subsidiaries have effectively sold forward approximately 2.0 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 250,000 GWh at an assumed 8.0 market heat rate) over the period from 2009 to 2014 at average annual sales prices ranging from $7.20 per MMBtu to $8.10 per MMBtu. EFH Corp. currently expects to hedge approximately 80% of the equivalent natural gas price exposure of its expected baseload generation output on a rolling five-year basis. For the period from 2009 to 2013, and taking into consideration the estimated portfolio impacts of TXU Energy’s retail electricity business, the hedging transactions described in the previous sentence result in EFH Corp. having effectively hedged approximately 81% of its expected baseload generation natural gas price exposure for such period (on an average basis for such period), assuming an 8.0 market heat rate. The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices. If market heat rates decline in the future, which would indicate a lessening of such correlation, EFH Corp. expects that the cash flows targeted under the long-term hedging program may not be achieved.

The long-term hedging program is comprised primarily of contracts with prices based on the NYMEX Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. EFH Corp. has hedged approximately 95% of the Houston Ship Channel versus Henry Hub pricing point risk for the 2009 period.

Beginning in the second quarter of 2008, EFH Corp. entered into related put and call transactions (referred to as collars), primarily for outer years of the program, that effectively hedge natural gas prices within a range. These transactions represented approximately 5% of the positions in the program at January 30, 2009, 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. EFH Corp. expects to employ both collars and, as has been the case, swap transactions for future hedging activity under its long-term hedging program. Under the terms of the collars, if forward natural gas prices are lower than the floor price, unrealized mark-to-market gains related to the hedges would be recognized in net income, and if forward prices are higher than the ceiling price, unrealized mark-to-market losses related to the hedges would be recognized in net income.

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Prior to March 2007, a significant portion of the instruments under the long-term hedging program were designated and accounted for as cash flow hedges. In March 2007, these instruments were dedesignated as allowed under SFAS 133. Subsequent changes in the fair value of these instruments are being recorded as unrealized gains and losses in net income, which has and could continue to result in significantly increased volatility in reported net income. Based on the size of the long-term hedging program as of January 30, 2009, a $1.00/MMBtu change in natural gas prices across the period from 2009 through 2014 would result in the recognition by EFH Corp. of up to approximately $2.0 billion in pretax unrealized mark-to-market gains or losses.

Reported unrealized mark-to-market net gains for the year ended December 31, 2008 totaled $2.6 billion, reflecting declines in forward prices of natural gas in 2008. 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 cumulative unrealized mark-to-market net losses or gains related to positions in the long-term hedging program totaled a net loss of $1.8 billion at December 31, 2007, a net gain of $871 million at December 31, 2008 and a net gain of $1.206 billion at January 30, 2009. These values can change materially as market conditions change.

As of December 31, 2008, more than 95% of the long-term hedging transactions were 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 “Liquidity And Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.

TCEH Interest Rate Swap Transactions — See discussion in Note 15 to Financial Statements regarding various interest rate swap transactions. As of December 31, 2008, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $17.55 billion principal amount of its senior secured debt maturing from 2009 to 2014. Taking into consideration these swap transactions, approximately 6% of EFH Corp.’s total long-term debt portfolio at December 31, 2008 was exposed to variable interest rate risk. In August 2008, swaps in effect at that time were dedesignated as cash flow hedges in accordance with SFAS 133, and subsequent changes in their fair value are being marked-to-market in net income (reported in interest expense and related charges). These swaps were dedesignated as a result of the intent to change the variable interest rate terms of the hedged debt (from three-month LIBOR to one-month LIBOR) in connection with the planned execution of interest rate basis swaps to further reduce the fixed borrowing costs. EFH Corp. may enter into additional interest rate hedges from time to time. Reported unrealized mark-to-market net losses related to all TCEH interest rate swaps totaled $1.477 billion for the year ended December 31, 2008. The cumulative unrealized mark-to-market net losses related to all TCEH interest rate swaps totaled $1.909 billion at December 31, 2008 ($364 million of which was reported in accumulated other comprehensive income) and $280 million at December 31, 2007 (reported in accumulated other comprehensive income) due to changes in market interest rates. These fair values can change materially as market conditions change.

Sale of Oncor Minority Interests— In November 2008, Oncor sold additional equity interests that resulted in an unaffiliated investor group acquiring a 19.75% minority stake and certain members of Oncor’s management indirectly acquiring a 0.21% stake in Oncor. The investor group was led by certain firms from Canada and Singapore and is not affiliated with any member of the Sponsor Group, Texas Holdings or EFH Corp. The investor group and management collectively paid $1.267 billion in cash for the minority stakes. See Note 18 to Financial Statements for additional information.

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The proceeds (net of closing costs) of $1.253 billion received by Oncor from the issuance of equity to the investor group and the contemporaneous issuance of equity to certain members of Oncor management were distributed ultimately to EFH Corp. EFH Corp. retains an interest of 80.04% in Oncor subsequent to these transactions. Under the terms of certain financing arrangements of EFH Corp. and TCEH, upon such distribution, under certain circumstances, EFH Corp. is required to repay certain outstanding intercompany loans from TCEH. In November 2008, EFH Corp. repaid the $253 million balance of such loans that related to payments of principal and interest on EFH Corp. debt. Regarding any excess proceeds, EFH Corp. may retain the funds for general corporate purposes, use the funds for repayment of debt, use the funds for certain investments, or contribute the funds to TCEH to be used for the same purposes.

Notice of Termination of Outsourcing Arrangements —During the fourth quarter of 2008, EFH Corp. and TCEH executed a Separation Agreement with Capgemini Energy LP (Capgemini), Capgemini America, Inc. and Capgemini North America, Inc. (collectively, CgE). Simultaneous with the execution of that Separation Agreement, Oncor entered into a substantially similar Separation Agreement with CgE. As a result of the “change of control” of EFH Corp. that occurred as a result of the Merger, each of TCEH and Oncor had the right to terminate, without penalty, its Master Framework Agreement with Capgemini. Under the Master Framework Agreements and related services agreements, Capgemini has provided to EFH Corp. and its subsidiaries outsourced support services, including information technology, customer care and billing, human resources, procurement and certain finance and accounting activities.

Consistent with the Master Framework Agreements, to provide for an orderly transition of the services, the Separation Agreements require that Capgemini provide termination assistance services until the services are transitioned back to EFH Corp. and/or to another service provider. The Separation Agreements provide that the services be transitioned by December 31, 2010 (June 30, 2011, in the case of the information technology services). Each Master Framework Agreement will terminate when these termination assistance services are completed. EFH Corp. (or its applicable subsidiary) previously provided a termination notice to Capgemini in respect of human resources services and customer care and revenue management services for TXU Energy. See Note 21 to Financial Statements for further discussion.

The effects of the termination of the outsourcing arrangements, including an accrual of $66 million for incremental costs to exit and transition the services, were included in the final Merger purchase price allocation (see Note 2 to Financial Statements).

Environmental Regulatory Matters —See discussion in Note 3 to Financial Statements regarding the invalidation of the EPA’s Clean Air Interstate Rule and the related impairment of intangible assets representing NOx and SO₂ emission allowances in the third quarter of 2008.

Texas Generation Facilities Development —EFH Corp. is developing three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in the state of Texas with a total estimated capacity of approximately 2,200 MW. Agreements were executed with EPC contractors to engineer and construct the units; design and procurement activities for the three units are essentially complete, and construction is well underway. Air permits for construction of all three units have been obtained. Aggregate cash capital expenditures for these three units are expected to total approximately $3.25 billion including all construction, site preparation and mining development costs, of which approximately $2.7 billion was spent as of December 31, 2008. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $5.0 billion upon completion of the units. The expected commercial operation dates of the units are as follows: Sandow in mid 2009 and Oak Grove’s two units in late 2009 and mid 2010, respectively. See discussion in Note 16 to Financial Statements under “Litigation Related to Generation Development” regarding pending litigation related to the new units.

The development program includes up to $500 million for investments in state-of-the-art emissions controls for the three new units. The development program also includes an environmental retrofit program under which Luminant will install additional environmental control systems at its existing lignite/coal-fueled generation facilities. Estimated capital expenditures associated with these additional environmental control systems total approximately $1.0 billion to $1.3 billion, of which $219 million was spent as of December 31, 2008. EFH Corp. has not yet completed all detailed cost and engineering studies for the additional environmental systems, and the cost estimates could materially change as EFH Corp. determines the details of and further evaluates the engineering and construction costs related to these investments.

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Oncor Technology Initiatives — Oncor continues to invest in technology initiatives that include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs.

In May 2008, Oncor acquired a vendor’s existing BPL-based “Smart Grid” network assets in Oncor’s service territory for $90 million in cash. These network assets include BPL equipment and technology such as fiber optics, embedded sensors and software analytics that are intended to enable Oncor to better monitor its electricity distribution network over up to one-sixth of its service territory. The network assets also included certain finished goods inventory and additional components. As part of the transaction, Oncor agreed to purchase software licenses and maintenance and operation services for a three-year period for approximately $35 million, including $25 million paid at the closing of the transaction. In addition, Oncor may, at its option, purchase additional equipment and utilize additional services from the vendor that would allow Oncor to expand the BPL network to up to one-half of its service territory.

Oncor Refund to Customers— Oncor provided a one-time $72 million refund to its REP customers in the September 2008 billing cycle. The refund was a commitment made by Oncor in connection with the PUCT’s review of the Merger and was recorded as a regulatory liability in the fourth quarter 2007 as part of purchase accounting. The refund was in the form of a credit on distribution fee billings.

While the refund was provided to REPs, the intent was that it be passed through by REPs to end-use retail consumers, and only those REPs that agreed to do so received their portion of the credit. Funds allocated to those REPs that did not agree to pass on the refunds were redistributed to the other customers served by REPs agreeing to pass on the refunds to ensure that the entire $72 million was refunded. To qualify, a retail customer must have been an electricity customer in the Oncor territory during December 2007 and still be served at the same location by a REP that agreed to pass on the refund. Commercial and industrial customers also received a portion of the $72 million refund, although it was based on their individual usage during calendar year 2007.

Oncor Matters with the PUCT —See discussion of these matters, including the awarded construction of $1.3 billion of transmission lines, below under “Regulation and Rates.”

Nuclear Generation Development —In September 2008, EFH Corp. filed a combined operating license application with the NRC for two new nuclear generation facilities, each with approximately 1,700 MW (gross capacity), at its existing Comanche Peak nuclear generation site. The application was accepted by the NRC for review in December 2008. In connection with the filing of the application, in January 2009, a subsidiary of EFH Corp. and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. Under the terms of the joint venture, known as Comanche Peak Nuclear Power Company LLC, a subsidiary of EFH Corp. holds an 88% ownership interest in the company, and MHI has a 12% stake.

In September 2008, EFH Corp. filed Part I of its loan guarantee application with the DOE for financing related to the proposed units. In December 2008, EFH Corp. filed Part II of the application with the DOE. The DOE continues to review the Part II application, and in accordance with DOE regulations, EFH Corp. intends to file a “Follow-On Submission,” updating its Part II application, in March 2009.

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KEY RISKS AND CHALLENGES

Following is a discussion of key risks and challenges facing management and the initiatives currently underway to manage such challenges.

Substantial Leverage, Uncertain Financial Markets and Liquidity Risk

EFH Corp.’s substantial leverage, resulting in part from debt incurred to finance the Merger, requires a substantial amount of cash flow to be dedicated to principal and interest payments and could adversely affect EFH Corp.’s ability to raise additional capital to fund operations, limit its ability to react to changes in the economy or its industry, and expose it to interest rate risk. Short-term borrowings and long-term debt, including amounts due currently, totaled $42.460 billion at December 31, 2008. Taking into consideration interest-rate swap transactions, as of December 31, 2008 approximately 94% of EFH Corp.’s total long-term debt portfolio is subject to fixed interest rates, at a weighted average interest rate of 8.70%. Principal payments on EFH Corp.’s debt in 2009 are expected to total approximately $372 million, and interest payments on long-term debt are expected to total approximately $3.140 billion.

While EFH Corp. believes its 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 2009 (see “Liquidity and Capital Resources” section below), there can be no assurance, considering the current dislocation and uncertainty in financial markets, that counterparties to EFH Corp.’s credit facilities will perform as expected through the maturity dates or hedging and trading counterparties, particularly related to the long-term hedging program, will meet their obligations to EFH Corp. Failure of such counterparties to meet their obligations or substantial unexpected changes in financial markets, the economy, the requirements of regulators or EFH Corp.’s industry or operations could result in constraints in EFH Corp.’s liquidity. See discussion of credit risk in “Item 3. Quantitative and Qualitative Disclosures About Market Risk” and discussion of credit facilities in “Financial Condition – Liquidity and Capital Resources” and in Note 15 to Financial Statements.

In addition, because its operations are capital intensive, EFH Corp. expects 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 its available credit facilities. If the credit crisis and related dislocation in the global financial system continue, EFH Corp.’s ability to economically access the capital or credit markets may be restricted at a time when EFH Corp. would like, or needs, to access those markets. Lack of such access could have an impact on EFH Corp.’s flexibility to react to changing economic and business conditions.

Natural Gas Price and Market Heat-Rate Exposure

Wholesale electricity prices in the ERCOT market generally move with the price of natural gas because marginal demand for electricity supply is generally met with natural gas-fueled generation facilities. Historically the price of natural gas has fluctuated due to the effects of weather, changes in industrial demand, supply availability, and other economic and market factors and such prices have been very volatile in recent years. Since 2005, natural gas prices ranged from below $5 per MMBtu to above $13 per MMBtu. The wholesale market price of power divided by the market price of natural gas represents the market heat rate. Market heat rate reflects the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity. Market heat rate movements also affect wholesale electricity prices.

In contrast to EFH Corp.’s natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating electricity from EFH Corp.’s nuclear and lignite/coal-fueled plants. All other factors being equal, these baseload generation assets, which provided 65% of supply volumes in 2008, increase or decrease in value as natural gas prices and market heat rates rise or fall, respectively, because of the effect of natural gas prices setting marginal wholesale power prices in ERCOT.

With the exposure to variability of natural gas prices, retail sales price management and hedging activities are critical to the profitability of the business and maintaining consistent cash flow levels. With the expiration of the formerly regulated rate mechanism on January 1, 2007, EFH Corp. has price flexibility in all of its retail markets with the exception of the sales to customers on fixed rate plans and a committed price cap at 2006 levels through 2009 for qualifying residential customers who remain on certain plans that were equal to the previously regulated rates. During 2008, the cap was below prevailing market prices and reduced retail revenues by approximately $130 million compared to 2007. Effective January 1, 2009, the cap increases by more than 2 cents per kWh.

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EFH Corp.’s approach to managing commodity 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 reduction of fixed costs 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.

As discussed above under “Significant Activities and Events,” EFH Corp. has implemented a long-term hedging program to mitigate the risk of future declines in wholesale electricity prices due to declines in natural gas prices.

The following sensitivity table provides estimates of the potential impact of movements in natural gas prices and market heat rates on realized pre-tax earnings for the periods presented. The estimates related to natural gas price sensitivity are based on EFH Corp.’s unhedged position as of January 30, 2009, which reflects estimates of electricity generation less amounts hedged through the long-term natural gas hedging program and amounts under existing wholesale and retail sales contracts. (For the balance of the 2009 period, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.)

	Balance 2009		2010		2011		2012		2013
$1.00 change in gas price (a)	$	22	$	65	$	69	$	111	$	290
0.1 change in market heat rate (b)	$	8	$	43	$	57	$	63	$	65

(a) Assumes conversion of electricity positions based on an approximate 8.0 market heat rate with natural gas being on the margin 75% to 90% of the time (i.e. when coal is forecast to be on the margin, no natural gas position is assumed to be generated).

(b) Based on Houston Ship Channel natural gas price as of January 30, 2009.

EFH Corp.’s market heat rate exposure is derived from its generation portfolio and is potentially impacted by generation capacity increases, particularly increases in lignite/coal- and nuclear-fueled capacity, as well as wind capacity, which could result in lower market heat rates. EFH Corp. expects that decreases in market heat rates would decrease the value of its generation assets because lower market heat rates generally result in lower wholesale electricity prices, and vice versa. EFH Corp. mitigates market heat rate risk through retail and wholesale electricity sales contracts and shorter-term market heat rate hedging transactions. EFH Corp. evaluates 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.

On an ongoing basis, EFH Corp. will continue monitoring its overall commodity risks and seek to balance its portfolio based on its desired level of exposure to natural gas prices and market heat rates and potential changes to its operational forecasts of overall generation and consumption in its native and growth business. 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 change from time to time.

See “Liquidity and Capital Resources” below for a discussion of the liquidity effects of the long-term hedging program. Also see additional discussion of risk measures below under “Quantitative and Qualitative Disclosures about Market Risk.”

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Competitive Markets and Customer Retention

Competitive retail activity in Texas resulted in declines in sales volumes in 2006 and 2007. Total retail sales volumes declined 5% and 11% in 2007 and 2006, respectively, as retail sales volume declines in EFH Corp.’s historical service territory were partially offset by growth in other territories. While competition was a factor, the decline in 2007 also reflected unusually cool summer weather. While this trend reversed in 2008, with a slight increase in total retail sales volumes and 2% growth in retail customers, competition remains robust. The area representing EFH Corp.’s historical service territory prior to deregulation, largely in north Texas, consisted of more than 3.1 million electricity consumers (measured by meter counts) as of year-end 2008. EFH Corp. currently has approximately 1.8 million retail customers in that territory and approximately 0.4 million retail customers in other competitive areas in Texas. In responding to the competitive landscape and full competition in the ERCOT marketplace, EFH Corp. is focusing on the following key initiatives:

• Maintaining competitive pricing initiatives as evidenced by price reductions on most residential service plans in fall 2008 and early 2009 and the 15% cumulative price reduction in 2007 applicable to residential customers under qualifying 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 plans to invest $100 million over the five-year period beginning in 2008 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, new product price/service offerings and a multichannel approach for the small business market.

Texas Generation Development Program

The undertaking of the development of three generation facilities in Texas as described above under “Significant Activities and Events” involves a number of risks. Aggregate cash capital expenditures to develop these three units are expected to total approximately $3.25 billion. While EFH Corp. believes the investment economics of the program are strong, estimates of future natural gas prices, market heat rates and effects of any greenhouse gas emissions laws or regulation may prove to be inaccurate, and returns on the investment could be significantly less than anticipated. Although substantial construction work has been completed, the program remains exposed to start-up delays, failure of the units to meet performance specifications and other project execution risks. Further, the development program has been subject to litigation and other environmental challenges. In the unlikely event these development activities are cancelled, EFH Corp. is exposed to impairment of construction work-in-process assets and project discontinuance costs, including equipment order cancellation penalties (see Note 16 to Financial Statements).

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 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, forward natural gas prices rose substantially in 2007 and part of 2008 before falling in the second half of 2008 and were especially volatile in 2008. 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. EFH Corp. believes 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 regulatory entities should continue to take actions that encourage competition in the industry. Regulatory and/or legislative intervention could disrupt the relationship between natural gas prices and electricity prices, which could impact the results of EFH Corp.’s long-term hedging strategy.

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New and Changing Environmental Regulations

EFH Corp. is subject to various environmental laws and regulations related to SO₂, NO_x and mercury emissions as well as other environmental contaminants that impact air and water quality. EFH Corp. is in compliance with all current laws and regulations, but regulatory authorities continue to evaluate existing requirements and consider proposals for changes. In addition, in July 2008, the US Court of Appeals for the D.C. Circuit (D.C. Circuit Court) invalidated CAIR, which required reductions of SO₂ and NO_x emissions from power generation facilities in 28 states, including Texas, where EFH Corp.’s generation facilities are located and remanded CAIR to the EPA to promulgate a rule consistent with its opinion. In December 2008, in response to an EPA petition, the D.C. Circuit Court reversed, in part, its previous ruling. Such reversal confirmed that CAIR is not valid, but allowed it to remain in place while the EPA revises CAIR to correct the previously identified shortcomings. At this time, EFH Corp. cannot predict the outcome of this decision, including how or when the EPA may revise CAIR. See further discussion in Part I under “Environmental Regulations and Related Considerations - Sulfur Dioxide, Nitrogen Oxide and Mercury Emissions” and see Note 3 to Financial Statements for discussion of impairment charges recorded as a result of the D.C. Circuit Court’s original ruling on CAIR.

EFH Corp. continues to closely monitor any potential legislative and regulatory changes pertaining to global climate change. In view of the fact that a substantial portion of its generation portfolio consists of lignite/coal-fueled generation plants and EFH Corp. is constructing three new lignite-fueled generation plants, EFH Corp.’s financial condition or results of operations could be materially adversely affected by the enactment of any legislation or regulation that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes on entities that produce GHG emissions. For example, federal, state or regional legislation or regulation addressing global climate change could result in EFH Corp. either incurring increased material costs in order for it to reduce its GHG emissions or to procure emission allowances or credits in order for it to comply with a mandatory cap-and-trade emissions reduction program or incurring increased taxes, which could be material, due to the imposition of a carbon tax. See further discussion in Part I under “Environmental Regulations and Related Considerations - Global Climate Change.”

Exposures Related to Nuclear Asset Outages

EFH Corp.’s nuclear assets are comprised of two generation units at Comanche Peak, each with a capacity of 1,150 MW. The Comanche Peak plant represents approximately 13% of EFH Corp.’s total generation capacity. The nuclear generation units represent EFH Corp.’s lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage, the unfavorable impact to pretax earnings is estimated to be approximately $2 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 16 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 complex and 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 plant as a precautionary measure.

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.

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APPLICATION OF CRITICAL ACCOUNTING POLICIES

EFH Corp.’s significant accounting policies are discussed in Note 1 to Financial Statements. EFH Corp. follows accounting principles generally accepted in the US. Application of these accounting policies in the preparation of EFH Corp.’s 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 of EFH Corp. that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.

Purchase Accounting

The Merger was accounted for under purchase accounting, whereby the purchase price of the transaction was allocated to EFH Corp.’s identifiable assets acquired and liabilities assumed based upon their fair values. The estimates of the fair values recorded were determined based on the principles in SFAS 157 (see Note 24 to Financial Statements) and reflect significant assumptions and judgments. Material valuation inputs for long-lived assets and liabilities included forward electricity and natural gas price curves and market heat rates, discount rates, nonperformance risk adjustments related to liabilities, retail customer attrition rates, generation plant operating and construction costs and asset lives. The valuations reflected considerations unique to the competitive wholesale power market in ERCOT as well as EFH Corp.’s assets. For example, the valuation of the baseload generation facilities considered EFH Corp.’s lignite fuel reserves and mining capabilities.

The results of the purchase price allocation included an increase in the total carrying value of EFH Corp.’s baseload generation plants and the recording of intangible assets related to the retail customer base, the TXU Energy trade name and emission credits. Further, commodity and other contracts not already subject to fair value accounting were valued, and amounts representing favorable or unfavorable contracts (versus market conditions as of the date of the Merger) were recorded as intangible assets or liabilities, respectively. Management believes all material intangible assets were identified. See Notes 2 and 3 to Financial Statements for details of the purchase price allocation and intangible assets recorded, respectively.

With respect to Oncor, the realization of its assets and settlement of its liabilities are largely subject to cost-based regulatory rate-setting processes. Accordingly, the historical carrying values of a majority of Oncor’s assets and liabilities are deemed to represent fair values. See discussion in Note 2 to Financial Statements regarding adjustments to the carrying values of Oncor’s regulatory asset and related long-term debt.

The excess of the purchase price over the estimated fair values of the net assets acquired was recorded as goodwill. The goodwill amount recorded upon finalization of purchase accounting totaled $23.2 billion. Management believes the drivers of the goodwill amount include the incremental value of the future cash flow potential of the baseload generation facilities, including facilities under construction, over the values assigned to those assets under purchase accounting rules, considering the market-pricing mechanisms and growth potential in the ERCOT market, as well as the value derived from the scale of the retail business. Management also believes that the goodwill reflects the value of the relatively stable, long-lived cash flows of the regulated business, considering the constructive regulatory environment and market growth potential. In accordance with SFAS 142, goodwill is not amortized to net income, but is required to be tested for impairment at least annually. SFAS 142 requires that goodwill be assigned to “reporting units”, which management has determined to be the Competitive Electric segment and the Regulated Delivery segment, which are almost entirely comprised of TCEH and Oncor, respectively. The assignment of goodwill was based on the relative estimated enterprise values of the operations as of the date of the Merger using discounted cash flow methodologies. Goodwill amounts assigned totaled $18.3 billion to the Competitive Electric segment and $4.9 billion to the Regulated Delivery segment. None of this goodwill balance is being deducted for tax purposes.

In the fourth quarter of 2008, EFH Corp. recorded a goodwill impairment charge of $8.860 billion. The goodwill impairment is EFH Corp.’s best estimate and subject to change upon finalization of fair value calculations which is expected to be completed during the first quarter of 2009. See discussion immediately below under “Impairment of Long-Lived Assets.”

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Impairment of Assets

EFH Corp. evaluates long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist, in accordance with SFAS 144 whenever events or changes in circumstances indicate that its 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 (as is the case for the natural gas-fueled generation assets discussed below). For EFH Corp.’s baseload 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 EFH Corp.’s 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 or whenever events or changes in circumstances indicate an impairment may exist, such as the possible impairments to long-lived assets discussed above. EFH Corp. tests goodwill and intangible assets with indefinite useful lives for impairment on October 1st each year. As required by SFAS 142, EFH Corp. has allocated goodwill to its reporting units, which are its two segments: Competitive Electric and Regulated Delivery, and goodwill impairment testing is performed at the reporting unit level. Under the SFAS 142 goodwill impairment analysis, if at the assessment date, a reporting unit’s carrying value exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair values of the reporting unit’s operating assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill amount is then compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied goodwill amount is written off as an impairment charge.

The determination of enterprise value involves a number of assumptions and estimates. EFH Corp. uses a combination of three fair value inputs to estimate enterprise values of its reporting units: internal discounted cash flow analyses (income approach), comparable company equity values and 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, 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 equity values involve using trading multiples of EBITDA of those selected companies to derive appropriate multiples to apply to the EBITDA of the reporting units. This approach requires an estimate, using historical acquisition data, of an appropriate control premium to apply to the reporting unit values calculated from such multiples. Critical judgments include the selection of comparable companies and the weighting of the three value inputs in developing the best estimate of enterprise value.

See Note 3 to Financial Statements for a discussion of the goodwill impairment charge of $8.860 billion (not deductible for income tax purposes) recorded in the fourth quarter of 2008. The charge represents approximately 38% of the goodwill balance resulting from purchase accounting for the Merger and reflects a decline of approximately 20% in the estimated value of EFH Corp. at year-end 2008 from the indicated value at the October 2007 Merger date. The impairment primarily arises from the dislocation in the capital markets that has increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of recent declines in market values of debt and equity securities of comparable companies. Also see Note 3 to Financial Statements for discussion of the impairment charge of $481 million ($310 million after-tax) related to the trade name intangible asset also recorded in the fourth quarter of 2008. The estimated fair value of this intangible asset is based on an assumed royalty methodology.

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In the fourth quarter of 2008, EFH Corp. recorded an impairment charge of $229 million ($147 million after-tax) related to its natural gas-fueled generation fleet. The value of those natural gas-fueled generation assets was previously increased to fair value as of October 10, 2007 along with the adjustment of EFH Corp.’s baseload generation assets, as part of purchase accounting for the Merger. An impairment charge of $198 million ($129 million after-tax) related to the fleet was recorded in 2006. The natural gas-fueled generation units are generally operated to meet peak demands for electricity, and the fleet is tested for impairment as an asset group. See Note 6 to Financial Statements for a discussion of the impairments. The estimated impairments were based on numerous judgments including forecasted production, forward prices of natural gas and electricity, overall generation availability in ERCOT and ERCOT grid congestion. In February 2009, EFH Corp. notified ERCOT of its plans to retire 11 of its natural gas-fueled units, totaling 2,229 MW of capacity (2,341 MW installed nameplate capacity), in May 2009 and mothball (idle) an additional four units, totaling 1,596 MW of capacity (1,675 MW installed nameplate capacity), in September 2009. ERCOT has 90 days from the date of the notification to request additional information or provide feedback on the proposed changes to the operation of these units.

In 2007, EFH Corp. recorded a net charge totaling $757 million ($492 million after-tax) (substantially all of which was in the Predecessor period) in connection with the 2007 suspension and subsequent cancellation of the development of eight coal-fueled generation units. This decision and subsequent terminations of equipment orders required an evaluation and substantial judgments regarding the recoverability of recorded assets associated with the development program. In determining the net charges recorded, EFH Corp. applied accounting rules for impairment of long-lived assets under SFAS 144 and for exit activities under SFAS 146. See Note 5 to Financial Statements for additional discussion.

Derivative Instruments and Mark-to-Market Accounting

EFH Corp. enters into contracts for the purchase and sale of energy-related commodities, and also enters into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Under SFAS 133, 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. The default accounting treatment for a derivative is to record changes in fair value 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. EFH Corp. adopted SFAS 157 concurrent with the Merger and estimates fair value as described in Note 24 to Financial Statements and discussed under “Fair Value Measurements” below.

SFAS 133 allows 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. These elections and designations are intended to match the accounting recognition of the contract’s financial performance to that of the transaction the contract is intended to hedge. “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.

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In accounting for cash flow hedges, changes in fair value 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 recognized in net income in the period that the hedged transactions are recognized. EFH Corp. continually assesses its hedge elections and under SFAS 133 could dedesignate positions currently accounted for as cash flow hedges, the effect of which could be more volatility of reported earnings as all changes in the fair value of the positions would be included in net income. In March 2007, the instruments making up a significant portion of the long-term hedging program that were previously designated as cash flow hedges were dedesignated as allowed under SFAS 133, 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 SFAS 133, and subsequent changes in their fair value are being marked-to-market in net income. See further discussion of the long-term hedging program and interest rate swap transactions above under “Significant Activities and Events.”

The following tables provide the effects on both net income and other comprehensive income of accounting for those derivative instruments that EFH Corp. has determined to be subject to fair value measurement under SFAS 133.

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Amounts recognized in net income (after-tax):
Unrealized net gains (losses) on positions marked-to-market in net income (a)	$	518		$	(955	)	$	(492	)	$	(2	)
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the period (a)		25			(56	)		(36	)		24
Unrealized ineffectiveness net gains (losses) on positions accounted for as cash flow hedges		(3	)	$	—			74			150
Reversals of previously recognized unrealized net (gains) losses related to cash flow hedge positions settled in the period		—			—			(15	)		5
Total	$	540		$	(1,011	)	$	(469	)	$	177
Amounts recognized in other comprehensive income (after-tax):
Net gains (losses) in fair value of positions accounted for as cash flow hedges (b)	$	(183	)	$	(177	)	$	(288	)	$	598
Net (gains) losses on cash flow hedge positions recognized in net income to offset hedged transactions (b)		122			—			(89	)		(45	)
Total	$	(61	)	$	(177	)	$	(377	)	$	553

(a) Amounts for 2008 include $1.503 billion in net gains related to commodity positions and $960 million in net losses related to interest rate swaps. Prior period amounts are essentially all related to commodity positions. Prior period amounts have been reclassified to include effects of changes in fair values of positions entered into and settled within the period. This change was made in association with the reclassification of commodity hedging and trading activities discussed in Note 1 to the Financial Statements.

(b) As discussed in Note 1 to the Financial Statements under “Basis of Presentation,” these amounts have been reclassified to reflect current presentation.

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

	Successor
	December 31, 2008			December 31, 2007
Net derivative asset related to commodity cash flow hedges	$	7		$	7
Net derivative liability related to interest rate hedges		(1,944	)		(316	)
Net commodity contract asset (liability) (a)	$	459		$	(2,009	)
Net accumulated other comprehensive loss included in shareholders’ equity (after-tax) amounts (b)	$	(238	)	$	(177	)

(a) Excludes amounts not arising from recognition of fair values such as payments and receipts of cash and other consideration associated with commodity hedging and trading activities.

(b) All amounts included in other comprehensive income as of October 10, 2007, which totaled $34 million in net gains, were eliminated as part of purchase accounting.

Fair Value Measurements

In addition to purchase accounting, EFH Corp. applies fair value accounting on a recurring basis to certain assets and financial instruments under the fair value hierarchy established in SFAS 157. EFH Corp. utilizes 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, EFH Corp. uses a mid-market valuation convention (the mid-point between bid and ask prices) as a practical expedient.

Level 1 and Level 2 assets and liabilities consist primarily of commodity-related contracts for natural gas and electricity derivative instruments entered into for hedging purposes, securities associated with the nuclear decommissioning trust, and interest rate swaps that are economic hedges of 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 by EFH Corp. 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. EFH Corp. utilizes correlation techniques to compare prices for inputs at both time periods to provide a basis to value the non-active derivative. (See Note 24 to Financial Statements for additional discussion of how broker quotes are utilized.)

Level 3 assets and liabilities consist primarily of more complex long-term power purchases and sales agreements, including longer-term wind and other power purchase and sales contracts and certain natural gas positions in the long-term hedging program. Level 3 assets and liabilities are valued using significant unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets and liabilities. EFH Corp. uses the most meaningful information available from the market, combined with its own internally developed valuation methodologies, to develop its best estimate of fair value. The determination of fair value for Level 3 assets and liabilities requires significant management judgment and estimation.

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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 EFH Corp.’s 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. Fair value adjustments include adjustments for counterparties’ credit risk, as well as EFH Corp.’s credit risk as appropriate, to determine a fair value measurement. Judgment is then applied in formulating those inputs. 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 EFH Corp.’s valuation of assets subject to fair value accounting, 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. EFH Corp.’s valuation of liabilities subject to fair value accounting takes into consideration the market’s view of its credit risk along with the existence of netting arrangements in place with the counterparty and credit enhancements posted by EFH Corp. EFH Corp. considers 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 $283 million at December 31, 2008 and represented approximately 7% of the assets measured at fair value, or less than 1% of total assets. Level 3 liabilities totaled $355 million at December 31, 2008 and represented approximately 7% of the liabilities measured at fair value, or less than 1% of total liabilities.

Valuations of several of EFH Corp.’s Level 3 assets and liabilities are based on long-dated price curves for electricity that are developed internally. Additionally, 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, 2008, a $5.00 per MWh change in electricity price assumptions across unobservable inputs, primarily related to the outer years in EFH Corp.’s long-dated pricing model (years that are not market observable) would cause an approximate $95 million change in net Level 3 liabilities. In addition, EFH Corp. has derivative contracts that are valued based on option-pricing models with unobservable inputs. A 10% increase in volatility and correlation related to these contracts would cause an approximate $8 million change in net Level 3 liabilities. See Note 24 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, 2008.

Revenue Recognition

EFH Corp.’s 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 $505 million, $477 million and $466 million at December 31, 2008, 2007 and 2006, respectively.

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Accounting for Contingencies

The financial results of EFH Corp. may be affected by judgments and estimates related to loss contingencies. A significant contingency that EFH Corp. accounts 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 totaled $81 million, $13 million, $46 million and $68 million for the year ended December 31, 2008, the period from October 11, 2007 to December 31, 2007, the period from January 1, 2007 to October 10, 2007, and the year ended December 31, 2006, respectively. The increase in bad debt expense in 2008 was driven by retail operations in south Texas, reflecting competitive customer acquisition and the effects of Hurricane Ike. See “Financial Condition – Bankruptcy Filing of Lehman Brothers Holdings Inc.” regarding a reserve for amounts due from subsidiaries of Lehman.

Litigation contingencies also may require significant judgment in estimating amounts to accrue. EFH Corp. accrues 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, 2008. See Item 3, “Legal Proceedings” for discussion of major litigation.

Accounting for Income Taxes

EFH Corp.’s 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, EFH Corp.’s 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, an adequate reserve has been made for any future taxes that may be owed as a result of any examination.

FIN 48 provides interpretive guidance for accounting for uncertain tax positions, and as discussed in Note 10 to the Financial Statements, EFH Corp. adopted this new standard January 1, 2007. See Notes 1 and 12 to Financial Statements for discussion of income tax matters.

Depreciation and Amortization

Depreciation expense related to generation facilities is based on the estimates of fair value and economic useful lives as determined in the application of purchase accounting described above. 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 23 to 32 years for the lignite/coal-fueled generation units and an average 43 years for the nuclear-fueled generation units. The estimated life of these baseload units is 60 years, the same as estimates prior to purchase accounting. See Note 1 to Financial Statements under “Property, Plant and Equipment” for discussion of the change from composite to asset-by-asset depreciation effective with the Merger.

As a result of cost-based regulatory rate-setting processes, the book value of the majority of Oncor’s assets and liabilities effectively represent fair value, and no adjustments to those regulated assets or liabilities were recorded as part of purchase accounting for the Merger. Depreciation expense for such assets totaled $330 million, $298 million and $301 million in 2008, 2007 and 2006, or 2.8% of carrying value in each of 2008, 2007 and 2006.

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Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 3 to Financial Statements for additional information.

Regulatory Assets

The financial statements at December 31, 2008 and 2007, reflect total regulatory assets of $2.071 billion and $1.593 billion, respectively. These amounts include $865 million and $967 million, respectively, of generation-related regulatory assets recoverable by securitization (transition) bonds as discussed immediately below. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. (See “Regulatory Assets and Liabilities” in Note 28 to Financial Statements.)

Generation-related regulatory asset stranded costs arising prior to the 1999 Restructuring Legislation became subject to recovery through issuance of $1.3 billion principal amount of transition bonds in accordance with a regulatory financing order. The carrying value of the regulatory asset upon final issuance of the bonds in 2004 represented the projected future cash flows to be recovered from REPs by Oncor through revenues as a transition charge to service the principal and fixed rate interest on the bonds. The regulatory asset is being amortized to expense in an amount equal to the transition charge revenues being recognized. As discussed in Note 2 to Financial Statements, the regulatory asset and related transition bonds were adjusted to fair value on the date of the Merger in accordance with purchase accounting rules.

Other regulatory assets that EFH Corp. believes are probable of recovery, but are subject to review and possible disallowance, totaled $913 million at December 31, 2008. These amounts consist primarily of employee retirement costs and storm-related service recovery costs.

Defined Benefit Pension Plans and OPEB Plans

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 eligible employees and their eligible dependents upon the retirement of such employees from EFH Corp. Reported costs of providing noncontributory defined pension benefits and OPEB are dependent upon numerous factors, assumptions and estimates.

Benefit costs are impacted by actual 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 actual equity market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.

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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:

	Successor						Predecessor
	December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			December 31, 2006
Pension costs under SFAS 87	$	21		$	(1	)	$	34		$	66
OPEB costs under SFAS 106		58			11			49			81
Total benefit costs	$	79		$	10		$	83		$	147
Less amounts deferred principally as a regulatory asset or property		(42	)		(8	)		(43	)		(84	)
Net amounts recognized as expense	$	37		$	2		$	40		$	63
Discount rates		6.55	%		6.45	%		5.90	%		5.75	%

See Note 22 to Financial Statements regarding other disclosures related to pension and OPEB obligations.

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

Assumption	Increase/(decrease) in 2008 Pension and OPEB Costs
Discount rate – 1% increase	$	(20	)
Discount rate – 1% decrease	$	36
Expected return on assets – 1% increase	$	(22	)
Expected return on assets – 1% decrease	$	22

Regulatory Recovery of Pension and OPEB Costs –In 2005, an amendment to PURA relating to pension and OPEB costs was enacted by the Texas Legislature. This amendment provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility. In addition to Oncor’s active and retired employees, these former employees largely include active and retired personnel engaged in TCEH’s activities, related to service of those additional personnel prior to the deregulation and disaggregation of EFH Corp.’s business effective January 1, 2002. The amendment additionally authorizes Oncor to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in Oncor’s current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Accordingly, in 2005, Oncor began deferring (principally as a regulatory asset or property) additional pension and OPEB costs consistent with the amendment, which was effective January 1, 2005. Amounts deferred are ultimately subject to regulatory approval.

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PRESENTATION AND ANALYSIS OF RESULTS

Management’s discussion and analysis of results of operations and cash flows has been prepared by analyzing the results of operations and cash flows of the Successor for the year ended December 31, 2008 on a stand-alone basis, by comparing the results of operations and cash flows of the Successor for the period October 11, 2007 through December 31, 2007 to the results of operations and cash flows of the Predecessor for the three months ended December 31, 2006 and by comparing the results of operations and cash flows of the Predecessor for the period January 1, 2007 through October 10, 2007 to the results of operations and cash flows of the Predecessor for the nine months ended September 30, 2006. To facilitate the discussion, certain volumetric and statistical data for 2007 have been presented as of and for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006 and as of and for the three months ended December 31, 2007 compared to the three months ended December 31, 2006. Such volumetric and statistical data are measured and reported on a monthly, quarterly and annual basis.

RESULTS OF OPERATIONS

EFH Corp. Consolidated Financial Results

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Three Months Ended December 31, 2006			Nine Months Ended September 30, 2006
Operating revenues (a)	$	11,364		$	1,994		$	8,044		$	2,283		$	8,420
Fuel, purchased power costs and delivery fees		(4,595	)		(644	)		(2,381	)		(602	)		(2,182	)
Net gain (loss) from commodity hedging and trading activities		2,184			(1,492	)		(554	)		92			61
Operating costs		(1,503	)		(306	)		(1,107	)		(355	)		(1,018	)
Depreciation and amortization		(1,610	)		(415	)		(634	)		(202	)		(628	)
Selling, general and administrative expenses		(957	)		(216	)		(691	)		(237	)		(582	)
Franchise and revenue-based taxes		(363	)		(93	)		(282	)		(114	)		(276	)
Impairment of goodwill		(8,860	)		—			—			—			—
Other income		80			14			69			30			91
Other deductions		(1,301	)		(61	)		(841	)		(25	)		(244	)
Interest income		27			24			56			16			30
Interest expense and related charges		(4,935	)		(839	)		(671	)		(190	)		(640	)
Income (loss) from continuing operations before income taxes and minority interests		(10,469	)		(2,034	)		1,008			696			3,032
Income tax (expense) benefit		471			673			(309	)		(227	)		(1,036	)
Minority interests in net loss of consolidated subsidiaries		160			—			—			—			—
Income (loss) from continuing operations		(9,838	)		(1,361	)		699			469			1,996
Income from discontinued operations, net of tax effect		—			1			24			6			81
Net income (loss)	$	(9,838	)	$	(1,360	)	$	723		$	475		$	2,077

(a) The operating revenues shown above reflect the change in classification for commodity hedging and trading activities discussed in Note 1 to the Financial Statements that resulted in an increase in operating revenues of $1.492 billion and $554 million for the Successor period from October 11, 2007 through December 31, 2007 and the Predecessor period from January 1, 2007 through October 10, 2007, respectively, and a decrease of $92 million and $61 million for the three months ended December 31, 2006 and nine months ended September 30, 2006, respectively.

Reference is made to comparisons of results by business segment following the discussion of consolidated results. The business segment comparisons provide additional detail and quantification of items affecting financial results.

62

Operating revenues are reflected in the table below:

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Three Months Ended December 31, 2006			Nine Months Ended September 30, 2006
Competitive Electric segment:
Total retail electricity revenues	$	6,328		$	1,142		$	5,014		$	1,410		$	5,543
Accrued customer appreciation bonus (Note 7 to Financial Statements)		—			—			—			(162	)		—
Wholesale electricity revenues		3,329			505			1,637			643			1,635
Wholesale balancing activities		(214	)		(9	)		(14	)		(25	)		(6	)
Amortization of intangibles (a)		(36	)		(50	)		—			—			—
Other operating revenues		380			83			247			84			274
Total Competitive Electric segment		9,787			1,671			6,884			1,950			7,446
Regulated Delivery segment		2,580			532			1,987			575			1,874
Net intercompany eliminations		(1,003	)		(209	)		(827	)		(242	)		(900	)
Total consolidated revenues	$	11,364		$	1,994		$	8,044		$	2,283		$	8,420

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

EFH Corp. Consolidated Financial Results — 2008

Operating revenues for 2008 totaled $11.364 billion. Operating revenues of $9.787 billion in the Competitive Electric segment included retail electricity revenues of $6.328 billion and wholesale electricity revenues of $3.329 billion. Retail electricity revenues were positively impacted by the effects of warmer than normal weather, an increase in residential customers and higher prices in the business markets. Wholesale electricity revenues reflected higher natural gas prices and a 21% increase in volumes as discussed further in the analysis of Competitive Electric segment results. Operating revenues of $2.580 billion in the Regulated Delivery segment reflected increased distribution and transmission tariffs and growth in points of delivery. Net intercompany sales eliminations reflected the elimination of sales from Oncor to REP subsidiaries of TCEH.

Fuel, purchased power costs and delivery fees for 2008 totaled $4.595 billion, which included $318 million of net expense representing amortization of the intangible net asset values of emission credits, coal purchase contracts and power purchase agreements and the stepped-up value of nuclear fuel resulting from purchase accounting. See additional discussion below in the analysis of Competitive Electric segment results of operations.

Net gain from commodity hedging and trading activities of $2.184 billion reflected unrealized mark-to-market net gains on positions in the long-term hedging program driven by the effect of a decrease in forward market prices of natural gas. See discussion above under “Long-Term Hedging Program” and below in the analysis of Competitive Electric segment results of operations.

Operating costs for 2008 totaled $1.503 billion, which included operations and maintenance expenses for power generation plants, fees paid to other transmission providers and salaries and benefits for plant personnel.

Depreciation and amortization for 2008 totaled $1.610 billion, which included $688 million of depreciation expense resulting from stepped-up property, plant and equipment values and $58 million of amortization expense largely related to the intangible value of retail customer relationships recorded in connection with purchase accounting and substantially all in the Competitive Electric segment.

SG&A expenses for 2008 totaled $957 million, which included costs associated with retail electricity operations, administrative and general salaries and benefits and consulting and professional fees. Also included were $35 million of Sponsor management fees.

See Note 3 to Financial Statements for discussion of the $8.860 billion goodwill impairment charge recorded in the fourth quarter of 2008.

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Other income for 2008 totaled $80 million, which consisted primarily of $44 million in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting, and $21 million net insurance recovery for damage to certain mining equipment. Other deductions for 2008 totaled $1.301 billion and includes impairment charges of $501 million related to NOx and SO₂ environmental allowances intangible assets and $481 million related to trade name intangible assets, both discussed in Note 3 to Financial Statements, $229 million in impairment charges related to the natural gas-fueled generation fleet and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which has filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 13 to Financial Statements for details of other income and deductions.

Interest expense and related charges for 2008 totaled $4.935 billion, a substantial portion of which was driven by borrowings for Merger-related financings and included unrealized mark-to-market net losses of $1.477 billion due to the effect of declining market interest rates on interest rate swaps, $146 million amortization of discount and debt issuance costs and $75 million of amortization of debt fair value discount resulting from purchase accounting.

Income tax benefit on loss from continuing operations for 2008 totaled $471 million. Excluding the impact of the $8.860 billion non-deductible goodwill impairment, the effective rate is 29.3%. The effective income tax rate of 29.3% as compared to the 35% statutory rate reflects interest accrued for uncertain tax positions and the effect of state income taxes, partially offset by the tax benefit of lignite depletion.

Loss from continuing operations (an after-tax measure) for 2008 totaled $9.838 billion. The loss in the Competitive Electric segment totaled $8.929 billion, which reflected impairment charges related to goodwill, trade name and environmental allowances intangible assets and the natural gas-fueled generation fleet, unrealized net losses on interest rate swaps, higher interest expense driven by Merger-related financings, and the effects of purchase accounting, partially offset by unrealized mark-to-market net gains in the long-term hedging program. The loss in the Regulated Delivery segment totaled $486 million, which primarily reflected the goodwill impairment charge. Corporate and Other net expenses totaled $423 million, which primarily reflected interest expense on Merger-related debt.

64

EFH Corp Consolidated Financial Results — 2007 and 2006

Successor Period from October 11, 2007 through December 31, 2007 Compared to the Three Month Predecessor Period Ended December 31, 2006

EFH Corp.’s operating revenues decreased $289 million, or 13%, to $1.994 billion in 2007.

• Operating revenues in the Competitive Electric segment decreased $279 million, or 14%, to $1.671 billion. The decrease reflected $268 million in lower retail electricity revenues and $138 million in lower wholesale electricity revenues, both decreases partially attributable to the ten fewer days in the 2007 period. The decrease in the retail electricity revenues also reflected residential price discount actions, partially offset by increased sales volumes. A $162 million ($105 million after-tax) charge was recorded in the 2006 period for a special residential customer appreciation bonus. See discussion in Note 7 to Financial Statements for details.

• Operating revenues in the Regulated Delivery segment decreased $43 million, or 7%, to $532 million primarily due to ten fewer days in the 2007 period, partially offset by higher distribution and transmission tariffs.

• A decrease in the net intercompany sales eliminations of $33 million, reflected lower sales by Oncor to REP subsidiaries of TCEH, while Oncor’s sales to nonaffiliated REPs increased.

Fuel, purchased power costs and delivery fees increased $42 million, or 7%, to $644 million. The increase reflects $67 million of net expense recorded in the 2007 period representing amortization of the intangible net asset values of emission credits, coal purchase contracts and power purchase agreements and the stepped-up value of nuclear fuel resulting from purchase accounting. See additional discussion below in the analysis of Competitive Electric segment results of operations.

The net loss from commodity hedging and trading activity of $1.492 billion in the 2007 period reflected unrealized mark-to-market net losses totaling $1.556 billion, driven by the effect of an increase in forward market prices of natural gas on positions in the long-term hedging program, compared to unrealized mark-to-market net gains of $58 million in the 2006 period. See discussion above under “Long-Term Hedging Program” and below in the analysis of Competitive Electric segment results of operations.

Operating costs decreased $49 million, or 14%, to $306 million.

• Operating costs in the Competitive Electric segment decreased $40 million, or 24%, to $124 million primarily reflecting reductions in costs largely resulting from the timing of maintenance outages.

• Operating costs in the Regulated Delivery segment decreased $9 million, or 5%, to $182 million reflecting the ten fewer days in the 2007 Successor period compared to the 2006 period, partially offset by higher fees paid to other transmission entities and higher vegetation management expenses.

Depreciation and amortization increased $213 million to $415 million. The increase includes $157 million of incremental depreciation expense resulting from stepped-up property, plant and equipment values and $81 million in incremental amortization expense largely related to the intangible value of retail customer relationships, both recorded in connection with purchase accounting and substantially all in the Competitive Electric segment.

65

SG&A expenses decreased $21 million, or 9%, to $216 million.

• SG&A expenses in the Competitive Electric segment decreased $13 million, or 8%, to $154 million, largely attributable to the ten fewer days in the 2007 period.

• SG&A expenses in the Regulated Delivery segment increased $6 million, or 15%, to $45 million, primarily reflecting increased employee incentive pay and benefit expense in the 2007 period.

• Corporate and Other SG&A expenses decreased $14 million, or 45%, to $17 million due primarily to lower salaries and incentive compensation in 2007 and $8 million in costs related to strategic initiatives in 2006, partially offset by $8 million of Sponsor management fees in 2007.

Other income totaled $14 million in the 2007 period and $30 million in the 2006 period. The 2007 amount includes $10 million in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting, and the 2006 amount includes $15 million of insurance recoveries related to the 2005 settlement of shareholders’ litigation and $12 million of amortization of a deferred gain on sale of a business that was eliminated in purchase accounting. Other deductions totaled $61 million in the 2007 period and $25 million in the 2006 period. The 2007 amount includes $51 million of professional fees incurred related to the Merger.

Interest expense and related charges increased $649 million to $839 million in the 2007 period, which was driven by borrowings for Merger-related financings.

Income tax benefits on pretax losses from continuing operations totaled $673 million in the 2007 period compared to income tax expense of $227 million on pretax income from continuing operations in the 2006 period. The effective income tax rate was 33.1% on a loss in the 2007 period compared to 32.6% on income in the 2006 period. The higher effective rate on a loss was due to the lignite depletion benefit, which was largely offset by non-deductible merger transaction costs, higher accrual of interest on uncertain tax positions and the effects of lower production deduction benefits in 2007.

Results from continuing operations (an after-tax measure) decreased $1.830 billion to a loss of $1.361 billion in the 2007 Successor period.

• Results in the Competitive Electric segment decreased $1.731 billion to a loss of $1.245 billion driven by significantly higher unrealized mark-to-market net losses on positions in the long-term hedging program, higher net interest expense driven by Merger-related financings and the effects of purchase accounting.

• Earnings in the Regulated Delivery segment increased $1 million to $63 million.

• Corporate and Other net expenses totaled $179 million in the 2007 Successor period and $79 million in the 2006 period. The amounts in 2007 and 2006 include recurring interest expense on outstanding debt and notes and advances from subsidiaries, as well as corporate general and administrative expenses. The after-tax increase of $100 million primarily reflects:

• $33 million in financial advisory, legal and other professional fees in 2007 directly related to the Merger;

• $31 million in higher net interest expense, driven by issuance of Merger-related debt;

• $8 million in lower other income reflecting the absence, due to purchase accounting, of amortization of a gain on the sale of a business, and

• decreased income tax benefit driven by nondeductible merger transactions costs,

partially offset by:

• $9 million decrease in SG&A expense as discussed above.

66

Predecessor Period from January 1, 2007 through October 10, 2007 Compared to the Nine Month Predecessor Period Ended September 30, 2006

EFH Corp.’s operating revenues decreased $376 million, or 4%, to $8.044 billion in 2007.

• Operating revenues in the Competitive Electric segment decreased $562 million, or 8%, to $6.884 billion. The decrease is primarily due to a $529 million decrease in retail electricity revenues, reflecting residential price discount actions and lower sales volumes. The volume decline was driven by the effects of a net loss of customers due to competitive activity and lower average consumption per customer due in part to unusually cool summer weather in 2007 and hotter than normal weather in 2006.

• Operating revenues in the Regulated Delivery segment increased $113 million, or 6%, to $1.987 billion. The revenue increase reflected growth in points of delivery and higher distribution and transmission tariffs, partially offset by lower average consumption, due in part to the cooler summer weather.

• A decrease in the net intercompany sales eliminations of $73 million reflected lower sales by Oncor to REP subsidiaries of TCEH, while its sales to nonaffiliated REPs increased.

Fuel, purchased power costs and delivery fees increased $199 million, or 9%, to $2.381 billion. The increase reflected purchases of power due to a scheduled refueling and major maintenance outage for one of the two Comanche Peak nuclear generation units. Maintenance work during the 55-day outage, which ended in April 2007 and drove an eleven percent decline in nuclear generation volumes, included the replacement of the unit’s steam generators and reactor vessel head. Higher fuel costs also reflected increased lignite mining expenses driven by significantly above normal summer rainfall.

Commodity hedging and trading activities resulted in a $554 million net loss in 2007 compared to a $61 million net gain in 2006. The net loss in 2007 reflects unrealized mark-to-market net losses totaling $722 million driven by the effect of higher forward market prices of natural gas on positions in the long-term hedging program. See discussion above under “Long-Term Hedging Program” and below in the analysis of Competitive Electric segment results of operations.

Operating costs increased $89 million, or 9%, to $1.107 billion.

• Operating costs in the Competitive Electric segment increased $29 million, or 7%, to $471 million. The increase reflected higher generation maintenance costs largely due to the scheduled outage in the spring of 2007 of one of the Comanche Peak nuclear generation units and the utilization of SO₂ emission credits in 2007 for the lignite/coal-fueled generation units, partially offset by lower costs resulting from generation technical support outsourcing agreements.

• Operating costs in the Regulated Delivery segment increased $58 million, or 10%, to $637 million. The increase reflected higher third-party transmission fees, expenses for equipment installation costs for a third party intended to facilitate Oncor’s technology initiatives and higher storm-driven service restoration costs, partially offset by lower vegetation management expenses.

Depreciation and amortization increased $6 million, or 1%, to $634 million. The increased expense reflects higher depreciation driven by ongoing investments in property, plant and equipment, largely offset by lower natural gas-fueled generation plant depreciation due to the impairment of the natural gas-fueled generation fleet in the second quarter of 2006, lower expense associated with mining reclamation obligations and lower amortization of the regulatory assets associated with the securitization bonds.

SG&A expenses increased $109 million, or 19%, to $691 million. The increase reflected higher expenses in the retail operations for marketing costs and professional fees for retail billing and customer care systems enhancements and strategic marketing projects, as well as higher costs associated with the new generation facilities development program, principally salaries and consulting expenses.

67

Other income totaled $69 million in 2007 and $91 million in 2006. Other deductions totaled $841 million in 2007 and $244 million in 2006. The 2007 other deductions amount included net charges of $755 million related to the cancelled development of eight coal-fueled generation units (see Note 5 to the Financial Statements). The 2006 other deductions amount includes a $198 million impairment charge related to natural gas-fueled generation units (see Note 6 to the Financial Statements). See Note 13 to the Financial Statements for details of other income and deductions.

Interest expense and related charges increased $31 million, or 5%, to $671 million in 2007. Of the increase, $27 million was attributable to the ten additional days in the 2007 period and reflected borrowings associated with the Merger. The remaining increase reflected higher average borrowings, primarily to fund capital expenditures, largely offset by increased capitalized interest.

Income tax expense on income from continuing operations totaled $309 million in 2007 and $1.036 billion in 2006. Excluding the $70 million deferred tax benefit in 2007 and the $41 million deferred tax charge in 2006 related to the Texas margin tax, the effective income tax rate was 37.6% in 2007 and 32.8% in 2006. (These unusual deferred tax adjustments distort the comparison; they have therefore been excluded for purposes of a more meaningful discussion). The increase in the effective rate primarily reflects the impacts of higher interest accrued related to uncertain tax positions and higher income-based taxes under the Texas margin tax.

Results from continuing operations (an after-tax measure) decreased $1.297 billion to $699 million in 2007.

• Earnings in the Competitive Electric segment decreased $1.159 billion to $722 million driven by unrealized mark-to-market net losses on positions in the long-term hedging program and the charges related to the cancelled development of eight coal-fueled generation units.

• Earnings in the Regulated Delivery segment decreased $17 million to $265 million driven by higher costs associated with the 2006 cities rate settlement and a decline in delivered volumes due to lower average consumption.

• Corporate and Other net expenses totaled $288 million in 2007 and $167 million in 2006. The amounts in 2007 and 2006 include recurring interest expense on outstanding debt and advances from subsidiaries, as well as corporate general and administrative expenses. The increase of $121 million (after-tax) primarily reflects:

• $33 million in nonrecurring gains in 2006 primarily related to the settlement of a telecommunications contract dispute, an insurance recovery of a litigation settlement and a gain on the sale of mineral rights;

• $25 million in financial advisory, legal and other professional fees in 2007 directly related to the Merger, and

• the write-off in 2007 of $25 million in previously deferred costs related to anticipated strategic transactions (including expected financings) that were no longer expected to be completed as a result of the Merger.

The increase in Corporate and Other net expenses also reflected higher 2007 expenses related to accrued interest on uncertain income tax positions and SG&A expenses driven by higher compensation and consulting expenses, partially offset by a deferred tax benefit related to the Texas margin tax as described in Note 11 to the Financial Statements.

68

Competitive Electric Segment

The following tables present financial operating results of the Competitive Electric segment for the Successor periods of the year ended December 31, 2008 and the period from October 11, 2007 through December 31, 2007 and for the Predecessor periods from January 1, 2007 through October 10, 2007, the three months ended December 31, 2006 and the nine months ended September 30, 2006. Volumetric and other statistical data have been presented as of and for the Successor period of the year ended December 31, 2008 and for the Predecessor periods for the nine months ended September 30, 2007, the three months ended December 31, 2006 and the nine months ended September 30, 2006. Volumetric and other statistical data have also been presented as of and for the three months ended December 31, 2007.

Financial Results

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Three Months Ended December 31, 2006			Nine Months Ended September 30, 2006
Operating revenues	$	9,787		$	1,671		$	6,884		$	1,950		$	7,446
Fuel, purchased power costs and delivery fees		(5,600	)		(852	)		(3,209	)		(847	)		(3,081	)
Net gain (loss) from commodity hedging and trading activities		2,184			(1,492	)		(554	)		92			61
Operating costs		(677	)		(124	)		(471	)		(164	)		(442	)
Depreciation and amortization		(1,092	)		(315	)		(253	)		(81	)		(252	)
Selling, general and administrative expenses		(682	)		(154	)		(489	)		(167	)		(403	)
Franchise and revenue-based taxes		(110	)		(30	)		(81	)		(42	)		(84	)
Impairment of goodwill		(8,000	)		—			—			—			—
Other income		34			2			22			18			5
Other deductions		(1,274	)		(8	)		(735	)		(10	)		(205	)
Interest income		61			10			271			66			137
Interest expense and related charges		(4,010	)		(609	)		(357	)		(73	)		(316	)
Income (loss) before income taxes		(9,379	)		(1,901	)		1,028			742			2,866
Income tax (expense) benefit		450			656			(306	)		(256	)		(985	)
Net income (loss)	$	(8,929	)	$	(1,245	)	$	722		$	486		$	1,881

69

Competitive Electric Segment

Sales Volume and Customer Count Data

	Successor			Three Months Ended December 31, 2007			Predecessor
	Year Ended December 31, 2008						Nine Months Ended September 30, 2007			Three Months Ended December 31, 2006			Nine Months Ended September 30, 2006
Sales volumes:
Retail electricity sales volumes – (GWh):
Residential		28,135			5,967			21,256			5,825			23,770
Small business (a)		7,363			1,622			5,861			1,707			6,716
Large business and other customers		13,945			3,591			10,946			3,329			10,703
Total retail electricity		49,443			11,180			38,063			10,861			41,189
Wholesale electricity sales volumes		47,270			11,198			27,914			11,061			25,870
Net sales (purchases) of balancing electricity to/from ERCOT (b)		(527	)		47			622			(394	)		1,268
Total sales volumes		96,186			22,425			66,599			21,528			68,327
Average volume (kWh) per retail customer (c):
Residential		14,780			3,197			11,399			3,086			12,235
Small business		28,743			6,337			22,421			6,319			23,926
Large business and other customers		475,886			104,582			276,764			73,121			210,515
Weather (service territory average) – percent of normal (d):
Percent of normal:
Cooling degree days		108.5	%		171.8	%		94.2	%		104.5	%		118.5	%
Heating degree days		92.5	%		89.7	%		106.2	%		90.9	%		71.2	%
Average revenues per MWh:
Residential	$	134.42		$	127.87		$	138.99		$	143.29		$	148.44
Customer counts:
Retail electricity customers (end of period and in thousands) (e):
Residential		1,932			1,875			1,858			1,871			1,904
Small business (a)		257			256			256			267			273
Large business and other customers		25			33			35			44			47
Total retail electricity customers		2,214			2,164			2,149			2,182			2,224

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

(b) See Note 1 to Financial Statements for discussion of reporting of ERCOT balancing activity.

(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).

(e) Based on number of meters.

70

Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Three Months Ended December 31, 2006			Nine Months Ended September 30, 2006
Operating revenues:
Retail electricity revenues:
Residential	$	3,782		$	654		$	3,064		$	835		$	3,528
Small business (a)		1,099			202			880			249			984
Large business and other customers		1,447			286			1,070			326			1,031
Total retail electricity revenues		6,328			1,142			5,014			1,410			5,543
Wholesale electricity revenues		3,329			505			1,637			643			1,635
Net sales (purchases) of balancing electricity to/from ERCOT (b)		(214	)		(9	)		(14	)		(25	)		(6	)
Amortization of intangibles (c)		(36	)		(50	)		—			—			—
Other operating revenues (d)		380			83			247			(78	)		274
Total operating revenues	$	9,787		$	1,671		$	6,884		$	1,950		$	7,446
Commodity hedging and trading activities:
Unrealized net gains (losses), including cash flow hedge ineffectiveness from changes in fair value (e)	$	2,290		$	(1,469	)	$	(646	)	$	25		$	203
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the current period (e)		(9	)		(87	)		(76	)		33			11
Realized net gains (losses) on settled positions (f)		(97	)		64			168			34			(153	)
Total gain (loss)	$	2,184		$	(1,492	)	$	(554	)	$	92		$	61
Estimated share of ERCOT retail markets (g):
Residential		37	%		36	%		36	%		37	%		38	%
Business markets		26	%		27	%		27	%		29	%		30	%

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

(b) See Note 1 to Financial Statements for discussion of reporting of ERCOT balancing activity.

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

(d) Includes a $162 million charge for a special customer appreciation bonus in the fourth quarter of 2006. This charge does not affect the computation of residential average revenues per MWh. See Note 7 to the Financial Statements.

(e) Amounts have been reclassified to include effects of changes in fair values of positions entered into and settled within the period; this change was made in association with the reclassification of commodity hedging and trading activities discussed in Note 1 to the Financial Statements.

(f) Includes physical commodity trading activity not subject to mark-to-market accounting of $44 million in net gains in 2008, $3 million in net losses in the period October 11, 2007 to December 31, 2007, $16 million in net losses in the period January 1, 2007 to October 10, 2007, $5 million in net losses for the three months ended December 31, 2006 and $29 million in net losses for the nine months ended September 30, 2006.

(g) Based on number of meters at end of period. Based on the number of customers who have choice. Calculations based on TXU Energy customer segmentation and ERCOT total customer counts.

71

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Three Months Ended December 31, 2006			Nine Months Ended September 30, 2006
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	95		$	21		$	66		$	20		$	65
Lignite/coal		640			127			467			122			353
Total baseload fuel		735			148			533			142			418
Natural gas fuel and purchased power		2,881			302			1,435			358			1,429
Amortization of intangibles (a)		318			67			—			—			—
Other costs		351			68			213			60			169
Fuel and purchased power costs (b)		4,285			585			2,181			560			2,016
Delivery fees (c)		1,315			267			1,028			287			1,065
Total	$	5,600		$	852		$	3,209		$	847		$	3,081
	Successor						Predecessor
	Year Ended December 31, 2008			Three Months Ended December 31, 2007			Nine Months Ended September 30, 2007			Three Months Ended December 31, 2006			Nine Months Ended September 30, 2006
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	4.92		$	4.64		$	4.59		$	4.39		$	4.25
Lignite/coal (d)	$	15.80		$	13.48		$	14.31		$	12.46		$	11.60
Natural gas fuel and purchased power	$	81.99		$	60.04		$	62.29		$	54.08		$	65.71
Delivery fees per MWh	$	26.33		$	26.64		$	25.60		$	26.10		$	25.60
Production and purchased power volumes (GWh):
Nuclear		19,218			5,157			13,664			4,501			15,292
Lignite/coal		44,923			12,197			34,297			11,329			34,252
Total baseload generation		64,141			17,354			47,961			15,830			49,544
Natural gas-fueled generation		4,122			500			3,491			502			3,487
Purchased power (b)		31,018			5,483			18,619			6,122			18,258
Total energy supply		99,281			23,337			70,071			22,454			71,289
Less line loss and power imbalances		3,095			912			3,472			926			2,962
Net energy supply volumes		96,186			22,425			66,599			21,528			68,327
Baseload capacity factors (%):
Nuclear		95.2	%		101.6	%		90.8	%		89.2	%		102.0	%
Lignite/coal		87.6	%		94.5	%		89.7	%		87.9	%		89.5	%
Total baseload		89.8	%		96.5	%		90.0	%		88.2	%		93.1	%

(a) 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.

(b) See Note 1 to the Financial Statements for discussion of reporting of ERCOT balancing activity.

(c) Includes delivery fee charges from Oncor that are eliminated in consolidation.

(d) Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs.

72

Competitive Electric Segment — Financial Results

Operating revenues are shown in the following table:

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Three Months Ended December 31, 2006			Nine Months Ended September 30, 2006
Total retail electricity revenues	$	6,328		$	1,142		$	5,014		$	1,410		$	5,543
Accrued customer appreciation bonus (Note 7 to Financial Statements)		—			—			—			(162	)		—
Wholesale electricity revenues		3,329			505			1,637			643			1,635
Wholesale balancing activities		(214	)		(9	)		(14	)		(25	)		(6	)
Amortization of intangibles (a)		(36	)		(50	)		—			—			—
Other operating revenues		380			83			247			84			274
Total operating revenues	$	9,787		$	1,671		$	6,884		$	1,950		$	7,446

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

Successor Period — Year Ended December 31, 2008

Operating revenues for 2008 totaled $9.787 billion. Retail electricity revenues of $6.328 billion were positively impacted in 2008 by the effects of warmer than normal weather, a 3% increase in residential customers and higher prices in the business markets reflecting higher wholesale electricity costs. Retail electricity revenues were negatively impacted by reduced business electricity usage, especially in the fourth quarter, and a 15% price discount phased in during 2007 to those residential customers in EFH Corp.’s historical territory with month-to-month service plans and a rate equivalent to the former regulated rate. Wholesale electricity revenues of $3.329 billion reflected higher natural gas prices and a 21% increase in volumes. The rise in natural gas prices through July 2008 reflected the overall trend of higher energy prices and increased demand in natural gas-fueled generation due to warmer weather in 2008. Higher wholesale sales volumes reflected several factors, including increased demand (due to warmer weather), baseload plant outages and congestion, as well as increased near-term bilateral power contracting activity due in part to increased demand and market volatility in 2008. Wholesale balancing activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, which are highly variable and in 2008 reflected weather-driven volatility, generation facility outages and congestion effects. Other operating revenues reflect retail natural gas sales and miscellaneous services revenues.

Fuel, purchased power costs and delivery fees for 2008 totaled $5.600 billion, which included $318 million of net expense representing amortization of the intangible net asset values of environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped-up value of nuclear fuel resulting from purchase accounting. Fuel and purchased power costs for 2008 also reflected:

• higher purchased power costs due to higher natural gas prices and volatility in the markets as hot weather and congestion issues in the spring resulted in power purchases at high prices, while Hurricane Ike and economic factors resulted in lower demand later in the year and sales of excess power back into the markets at lower prices;

• higher purchased power volumes due to planned and unplanned baseload generation plant outages and the factors that drove wholesale sales volumes as described above;

• higher fuel costs in natural gas-fueled generation plants due to higher natural gas prices; and

• higher usage and prices (including transportation costs) of purchased coal.

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Results from commodity hedging and trading activities include realized and unrealized gains and losses associated with financial instruments used for commodity hedging and trading purposes, as well as gains and losses on physical sales and purchases of commodities for trading and hedging purposes. A substantial majority of the commodity hedging activities are intended to mitigate the risk of commodity price movements on future revenues and involve natural gas positions entered into as part of the long-term hedging program. The results of these activities have been volatile because of the effects of movements in forward natural gas prices on unrealized mark-to-market valuations. Following is an analysis of results from commodity hedging and trading activities for 2008:

Unrealized mark-to-market net gains totaling $2.281 billion include:

• $2.324 billion in net gains related to hedge positions, which includes $2.282 billion in net gains from changes in fair value and $42 million in net gains that represent reversals of previously recorded fair values of positions settled in the period;

• $68 million in “day one” net losses related to large hedge positions (see Note 19 to Financial Statements), and

• $25 million in net gains related to trading positions, which includes $76 million in net gains from changes in fair value and $51 million in net losses that represent reversals of previously recorded fair values of positions settled in the period.

Realized net losses totaling $97 million include:

• $177 million in net losses related to hedge positions that primarily offset hedged electricity revenues recognized in the period, and

• $80 million in net gains related to trading positions.

Operating costs for 2008 totaled $677 million and primarily reflected operations and maintenance expenses for power generation plants and salaries and benefits for plant personnel. Costs in 2008 reflected increased unplanned lignite plant outages, refueling of both nuclear-fueled units in 2008 as compared to only one unit being refueled in 2007 based on a normal cycle, an increase in property taxes and costs associated with combustion turbines now operated for TCEH’s own benefit.

Depreciation and amortization expense for 2008 totaled $1.092 billion and included $688 million of depreciation expense from stepped-up property, plant and equipment values and $51 million in amortization expense related to the intangible value of retail customer relationships, both resulting from the effects of purchase accounting. Depreciation expense also reflects normal additions and replacements of equipment in generation operations.

SG&A expense for 2008 totaled $682 million and includes retail operations, administrative and general salaries and benefits and consulting and professional fees. Such expenses reflected increased retail staffing and related expenses to support customer growth initiatives, retail computer system enhancement costs and higher levels of bad debt expense driven by residential customer growth in south Texas and Hurricane Ike.

See Note 3 to Financial Statements for discussion of the $8.0 billion goodwill impairment charge recorded in the fourth quarter of 2008.

Other income totaled $34 million and other deductions totaled $1.274 billion for 2008. Other income includes an insurance recovery of $21 million and mineral rights royalty income of $4 million. Other deductions includes impairment charges of $501 million related to NO_x and SO₂ environmental allowances intangible assets and $481 million related to trade name intangible assets, both discussed in Note 3 to Financial Statements, $229 million in impairment charges related to the natural gas-fueled generation fleet discussed in Note 6 to Financial Statements and $26 million in charges to reserve for net receivables (excluding termination related charges) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which has filed for protection under Chapter 11 of the US Bankruptcy Code.

Interest income totaled $61 million for 2008 and primarily reflected interest on loans to affiliates.

74

Interest expense and related charges for 2008 totaled $4.010 billion, a substantial portion of which was driven by borrowings for Merger-related financings and included unrealized mark-to-market net losses of $1.477 billion on interest rate swaps, $119 million amortization of discount and debt issuance costs and $17 million of amortization of debt fair value discount resulting from purchase accounting.

Income tax benefit for 2008 was $450 million. Excluding the impact of the $8.0 billion non-deductible goodwill impairment, the effective rate was 32.6%. The effective rate of 32.6% on a loss compared to the 35% federal statutory rate reflects the impact of state income taxes, interest accrued for uncertain tax positions and non-deductible interest expense and losses on certain benefit plans, partially offset by the effect of lignite depletion.

Net loss for 2008 totaled $8.929 billion reflecting impairment charges related to goodwill, trade name and environmental allowances intangible assets and the natural gas-fueled generation fleet, unrealized net losses on interest rate swaps, higher interest expense driven by Merger-related financings, and the effects of purchase accounting, partially offset by unrealized mark-to-market net gains on positions in the long-term hedging program.

Successor Period from October 11, 2007 through December 31, 2007 Compared to the Three Month Predecessor Period Ended December 31, 2006

Total operating revenues decreased $279 million, or 14%, to $1.671 billion.

The $268 million, or 19%, decrease in retail electricity revenues reflected the following:

• The decrease in retail electricity revenues was partially due to $186 million in revenues attributable to the ten fewer days in the 2007 period.

• Lower average pricing (including customer mix effects) was driven by residential price discounts, including a six percent price discount effective with meter reads on March 27, 2007, an additional four percent price discount effective with meter reads on June 8, 2007, and another five percent price discount effective with meter reads on October 24, 2007 to those residential customers in EFH Corp.’s historical service territory with month-to-month service plans and a rate equivalent to the former regulated rate. Lower average pricing also reflected new competitive product offerings in residential and small business markets and a change in customer mix in the large business market.

• A 3% increase in retail sales volumes partially offset the effect of lower average pricing. Large business market volumes increased 8% driven by successful contracting with larger customers. Residential volumes increased 2% driven by warmer than normal fall weather. Small business volumes declined 5% reflecting competitive activity.

• Total retail electricity customer counts at December 31, 2007 declined 1% from December 31, 2006.

Wholesale electricity revenues decreased $138 million, or 21%. Of the decrease, $66 million was attributable to the ten fewer days in the 2007 period. Lower average prices contributed to the decrease and reflected lower natural gas prices during 2007. The pricing impact was partially offset by volume growth driven in part by the decline in retail sales.

Wholesale sales and purchases of electricity are reported gross in the income statement only if the transactions are scheduled for physical delivery with ERCOT.

75

Fuel, purchased power costs and delivery fees increased $5 million, or 1%, to $852 million. The ten fewer days in the 2007 period resulted in $123 million in lower costs. The 2007 period included $67 million of incremental net expense representing 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. Higher fuel costs reflected an 8% increase in lignite/coal-fueled generation and an increase in mining expenses that was driven by significantly above normal summer rainfall. A decrease in purchased power costs reflected the timing of planned nuclear outages (fall of 2006 compared to spring of 2007) and substantially fewer lignite/coal-fueled unit outages in 2007.

Results from commodity hedging and trading activities include realized and unrealized gains and losses associated with financial instruments used for commodity hedging and trading purposes, as well as gains and losses on physical sales and purchases of commodities for trading and certain commodity hedging purposes. A substantial majority of the commodity hedging activities are intended to mitigate the risk of commodity price movements on future revenues and involve natural gas positions entered into as part of the long-term hedging program. The results of these activities have been volatile because of the effects of movements in forward natural gas prices on unrealized mark-to-market valuations. Following is an analysis of activities for the periods:

Period from October 11, 2007 through December 31, 2007— Unrealized mark-to-market net losses totaling $1.556 billion include:

• $1.533 billion in net losses related to hedge positions, which includes $1.461 billion in net losses from changes in fair values and $72 million in net losses that represent reversals of previously recorded fair values of positions settled in the period. These losses are driven by the effect of higher natural gas prices in forward periods on positions in the long-term hedging program;

• $15 million in net losses related to trading positions, which represent reversals of previously recorded fair values of positions settled in the period; and

• $8 million in “day one” losses related to the large hedge positions entered into at below-market prices.

Realized net gains totaling $64 million include:

• $73 million in net gains related to hedge positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the period, and

• $9 million in net losses related to trading positions.

Three Months Ended December 31, 2006— Unrealized mark-to-market net gains totaling $58 million include:

• $32 million in net gains related to hedge positions, which includes $13 million in net gains from changes in fair values and $19 million in net gains that represent reversals of previously recorded fair values of positions settled in the period, and

• $26 million in net gains related to trading positions, which includes $12 million in net gains from changes in fair values and $14 million in net gains that represent reversals of previously recorded fair values of positions settled in the period.

Realized net gains totaling $34 million include:

• $37 million in net gains on settlement of economic hedge positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the current period, and

• $3 million in net losses related to trading positions.

Operating costs decreased $40 million, or 24%, to $124 million in 2007. Of the decrease, $19 million was attributable to the ten fewer days in the 2007 period. The decrease also reflected reductions in costs largely resulting from the timing of maintenance outages. Planned outages of nuclear units occurred in the fall of 2006 and the spring of 2007, and there were substantially fewer lignite/coal-fueled unit outage days in 2007.

76

Depreciation and amortization increased $234 million in 2007. The 2007 period included $157 million of incremental depreciation expense resulting from stepped-up property, plant and equipment values and $79 million in incremental amortization expense related to the intangible value of retail customer relationships recorded in connection with purchase accounting. The ten fewer days in the 2007 period resulted in $8 million in lower costs. Higher baseload generation plant depreciation due to ongoing investments in property, plant and equipment was largely offset by lower natural gas-fueled generation plant depreciation due to the impairment of the natural gas-fueled generation fleet in the second quarter of 2006 and lower expense associated with mining reclamation obligations.

SG&A expenses decreased $13 million, or 8%, to $154 million in 2007. Of the decrease, $15 million was attributable to the ten fewer days in the 2007 period. SG&A expenses also reflected lower bad debt expenses, driven by a decrease in delinquencies and lower accounts receivable, and higher severance costs in 2006 largely offset by increased retail expenses for marketing, professional fees and salary and benefits, which were driven by an increase in staffing.

Franchise and revenue-based taxes decreased $12 million, or 29%, to $30 million in 2007. Of the decrease, $3 million was attributable to the ten fewer days in the 2007. The remaining decrease reflected lower state gross receipts taxes due to lower revenues.

Other income totaled $2 million in 2007 and $18 million in 2006. The 2006 amount included $4 million in net gains on the sale of assets, $4 million in mineral royalty income, a $3 million sales tax refund and $2 million in insurance recoveries. Other deductions totaled $8 million in 2007 and $10 million in 2006. The 2007 other deductions included equity losses of unconsolidated subsidiaries and net charges related to the cancellation of eight coal-fueled generation plants. The 2006 other deductions included litigation charges and equity losses of unconsolidated subsidiaries.

Interest income decreased $56 million to $10 million in 2007 reflecting lower average balances of loans to affiliates.

Interest expense and related charges increased by $536 million to $609 million in 2007. The ten fewer days in the 2007 period resulted in $15 million in decreased charges. The increase reflected higher average balances and higher average rates driven by Merger-related financings.

Income tax benefit totaled $656 million in 2007 compared to income tax expense of $256 million in 2006. The effective income tax rate was 34.5% on a loss in the 2007 period compared to 34.5% on income in the 2006 period. The effective rate on a loss reflected an increase due to the lignite depletion benefit, which was offset by lower production deduction benefits, higher accrual of interest on uncertain tax positions and, as the result of purchase accounting, the absence of investment tax credit amortization in 2007.

Results from operations decreased $1.731 billion to a net loss of $1.245 billion in 2007 driven by significantly higher unrealized mark-to-market net losses on positions in the long-term hedging program, higher net interest expense driven by Merger-related financings and the effects of purchase accounting.

77

Predecessor Period from January 1, 2007 through October 10, 2007 Compared to the Nine Month Predecessor Period Ended September 30, 2006

Total operating revenues decreased $562 million, or 8%, to $6.884 billion.

The $529 million, or 10%, decrease in retail electricity revenues reflected the following:

• The decrease in retail electricity revenues was partially offset by $186 million in revenues attributable to the ten additional days in the 2007 period.

• Retail sales volumes declined 8%. Residential and small business volumes declined 11% and 13%, respectively, reflecting the effects of a net loss of customers due to competitive activity and lower average consumption per customer of 7% in the residential market and 6% in the small business market due in part to unusually cool summer weather in 2007 and hotter than normal weather in 2006. Large business market volumes increased 2% reflecting a change in customer mix.

• Lower average pricing (including customer mix effects) was driven by residential price discounts, including a six percent price discount effective with meter reads on March 27, 2007, and an additional four percent price discount effective with meter reads on June 8, 2007, to those residential customers in EFH Corp.’s historical service territory with month-to-month service plans and a rate equivalent to the former regulated rate. Lower average pricing also reflected new competitive product offerings in residential and small business markets and a change in customer mix in the large business market.

• Total retail electricity customer counts declined 3% from September 30, 2006, which consisted of a 2% decline in total residential customer counts and a decline of 6% in small business customer counts.

Wholesale electricity revenues increased $2 million. An increase of $66 million was attributable to the ten additional days in the 2007 period with the remaining variance due to lower prices as average wholesale prices declined approximately 11% reflecting lower natural gas prices during 2007, the effect of which was partially offset by volume growth of 8% due in part to the decline in retail sales volumes associated with competitive activity.

Wholesale sales and purchases of electricity are reported gross in the income statement only if the transactions are scheduled for physical delivery with ERCOT.

Fuel, purchased power costs and delivery fees increased $128 million, or 4%, to $3.209 billion. Of the increase in costs, $123 million was attributable to the ten additional days in the 2007 period. Purchases of power increased due to a scheduled refueling and major maintenance outage for one of the two Comanche Peak nuclear units. Higher fuel costs reflected increased lignite mining costs due to inefficiencies caused by significantly above normal summer rainfall. These factors were largely offset by lower delivery fees due to lower retail sales volumes.

Results from commodity hedging and trading activities include realized and unrealized gains and losses associated with financial instruments used for commodity hedging and trading purposes, as well as gains and losses on physical sales and purchases of commodities for trading and certain commodity hedging purposes. A substantial majority of the commodity hedging activities are intended to mitigate the risk of commodity price movements on future revenues and involve natural gas positions entered into as part of the long-term hedging program. The results of these activities have been volatile because of the effects of movements in forward natural gas prices on unrealized mark-to-market valuations. Following is an analysis of activities for the periods:

78

Period from January 1, 2007 through October 10, 2007— Unrealized mark-to-market net losses totaling $722 million include:

• $566 million in net losses related to hedge positions, which includes $528 million in net losses from changes in fair values and $38 million in net losses that represent reversals of previously recorded fair values of positions settled in the period. These losses are driven by the effect of higher natural gas prices in forward periods on positions in the long-term hedging program;

• $90 million in hedge ineffectiveness net gains, which includes $111 million of net gains from changes in fair values and $21 million in net losses that represent reversals of previously recorded ineffectiveness net gains related to positions settled in the period. These amounts relate to positions accounted for as cash flow hedges;

• $45 million in net losses related to trading positions, which includes $28 million in net losses from changes in fair values and $17 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;

• $231 million in “day one” losses related to large hedge positions entered into at below-market prices, and

• a $30 million “day one” gain related to a power purchase agreement.

Realized net gains totaling $168 million include:

• $125 million in net gains related to hedge positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the period, and

• $43 million in net gains related to trading positions.

Nine Months Ended September 30, 2006— Unrealized mark-to-market net gains totaling $214 million include:

• $46 million in net losses related to hedge positions, which includes $4 million in net losses from changes in fair values and $42 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;

• $301 million in hedge ineffectiveness net gains, which includes $289 million of net gains from changes in fair values and $12 million in net gains that represent reversals of previously recorded ineffectiveness net losses related to positions settled in the period. These amounts relate to positions accounted for as cash flow hedges;

• $68 million in net gains related to trading positions, which includes $27 million in net gains from changes in fair values and $41 million in net gains that represent reversals of previously recorded fair values of positions settled in the period, and

• $109 million in “day one” losses on commodity price hedges entered into at below-market prices.

Realized net losses totaling $153 million include:

• $102 million in net losses on settlement of economic hedge positions that offset hedged electricity revenues recognized in the current period, and

• $51 million in net losses related to trading positions.

Operating costs increased $29 million, or 7%, to $471 million in 2007. Of the increase, $19 million was attributable to the ten additional days in the 2007 period. The remaining increase reflected $18 million in higher generation maintenance costs largely due to the scheduled outage in the spring of 2007 of one of the Comanche Peak nuclear generation units and $7 million for the utilization of SO₂ emission credits in 2007 for the lignite/coal-fueled generation units, partially offset by lower costs largely resulting from generation technical support outsourcing service agreements.

Depreciation and amortization increased $1 million for the period. Expenses totaling $8 million were attributable to the ten additional days in the 2007 period. The remaining decrease was driven by lower natural gas-fueled generation plant depreciation due to the impairment of the natural gas-fueled generation fleet in the second quarter of 2006 and lower expense associated with mining reclamation obligations, partially offset by higher baseload generation plant depreciation, driven by ongoing investments in property, plant and equipment.

79

SG&A expenses increased $86 million, or 21%, to $489 million in 2007. Of the increase, $15 million was attributable to the ten additional days in the 2007 period. The remaining increase reflected $27 million in increased retail marketing expenses, $16 million in costs associated with the new generation facilities development program, principally salaries and consulting expenses, and $14 million in higher professional fees primarily for retail billing and customer care systems enhancements and marketing/strategic projects. The increase was also due to higher salary and benefit costs primarily driven by an increase in staffing in retail operations and higher costs due to reallocation of Capgemini outsourcing fees. Partially offsetting the increase in SG&A expenses were lower bad debt expenses driven by a decrease in delinquencies and lower accounts receivable balances.

Other income totaled $22 million in 2007 and $5 million in 2006. Other income in 2007 includes $8 million of royalty income and $6 million in penalties received due to nonperformance under a coal transportation agreement.

Other deductions totaled $735 million in 2007 and $205 million in 2006. The 2007 amount includes:

• net charges of $755 million related to the cancelled development of eight coal-fueled generation units (see Note 5 to the Financial Statements);

• $10 million in charges related to the termination of a railcar operating lease, and

• a $48 million credit from reducing a liability previously recorded for leases related to gas-fueled combustion turbines that EFH Corp. ceased operating for its own benefit (see Note 13 to the Financial Statements).

The 2006 amount includes:

• a $198 million charge related to the write-down of natural gas-fueled generation units to fair value (see Note 6 to the Financial Statements), and

• $8 million in equity losses (representing amortization expense) related to the ownership interest in the EFH Corp. subsidiary holding the capitalized software licensed to Capgemini;

partially offset by a $12 million credit related to the favorable settlement of a counterparty default under a coal contract (the original charge related to the default was recorded in this line item in 2005).

Interest income increased $134 million to $271 million in 2007 reflecting higher average advance balances and higher average rates on advances to affiliates.

Interest expense and related charges increased by $41 million to $357 million in 2007. Of the increase, $15 million was attributable to the ten additional days in the 2007 period. The remaining increase of $26 million reflected $53 million due to higher average borrowings and $20 million due to higher average interest rates, partially offset by $47 million in increased capitalized interest.

Income tax expense totaled $306 million in 2007 compared to $985 million in 2006. Excluding the $32 million deferred tax benefit in 2007 and the $42 million deferred tax charge in 2006 related to the Texas margin tax as described in Note 11 to the Financial Statements, the effective rate was 32.9% in both 2007 and 2006. (These unusual deferred tax adjustments distort the comparison; they have therefore been excluded for purposes of a more meaningful discussion).

Results from continuing operations decreased $1.159 billion to $722 million in 2007 driven by unrealized mark-to-market losses on positions in the long-term hedging program and charges related to the cancellation of the development of eight lignite/coal-fueled generation units.

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Regulated Delivery Segment

The following tables present financial operating results of the Regulated Delivery segment for the Successor periods of the year ended December 31, 2008 and the period from October 11, 2007 through December 31, 2007 and for the Predecessor periods from January 1, 2007 through October 10, 2007, the three months ended December 31, 2006 and the nine months ended December 31, 2006. Volumetric and other statistical data have been presented for the Successor periods of the year ended December 31, 2008 and the three months ended December 31, 2007 and for the Predecessor periods for the nine months ended September 30, 2007, the three months ended December 31, 2006 and the nine months ended September 30, 2006.

Financial Results

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Three Months Ended December 31, 2006			Nine Months Ended September 30, 2006
Operating revenues	$	2,580		$	532		$	1,987		$	575		$	1,874
Operating costs		(828	)		(182	)		(637	)		(191	)		(579	)
Depreciation and amortization		(492	)		(96	)		(366	)		(117	)		(359	)
Selling, general and administrative expenses		(164	)		(45	)		(139	)		(39	)		(138	)
Franchise and revenue-based taxes		(255	)		(62	)		(198	)		(73	)		(189	)
Impairment of goodwill		(860	)		—			—			—			—
Other income		45			11			3			—			2
Other deductions		(19	)		(7	)		(27	)		(11	)		(13	)
Interest income		45			12			44			15			43
Interest expense and related charges		(317	)		(70	)		(242	)		(73	)		(213	)
Income before income taxes		(265	)		93			425			86			428
Income tax expense (a)		(221	)		(30	)		(160	)		(24	)		(146	)
Net income (loss)	$	(486	)	$	63		$	265		$	62		$	282

(a) Effective with the sale of minority interests (see Note 18 to Financial Statements), Oncor is taxed as a partnership and thus not subject to income taxes; however, EFH Corp. evaluates the results of its segments as if they were stand-alone entities subject to income taxes.

Operating Data

	Successor	Three Months Ended December 31, 2007	Predecessor
	Year Ended December 31, 2008		Nine Months Ended September 30, 2007	Three Months Ended December 31, 2006	Nine Months Ended September 30, 2006
Operating statistics – volumes:
Electric energy delivered (GWh)	107,672	24,622	81,523	23,618	83,480
Reliability statistics (a):
System Average Interruption Duration Index (SAIDI) (nonstorm)	85.4	77.9	79.2	79.1	78.3
System Average Interruption Frequency Index (SAIFI) (nonstorm)	1.1	1.1	1.1	1.2	1.2
Customer Average Interruption Duration Index (CAIDI) (nonstorm)	74.7	70.6	69.5	67.5	67.3
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters)	3,123	3,093	3,087	3,056	3,051

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	Successor				Predecessor
	Year Ended December 31, 2008		Period from October 11, 2007 through December 31, 2007		Period From January 1, 2007 through October 10, 2007		Three Months Ended December 31, 2006		Nine Months Ended September 30, 2006
Operating revenues:
Electricity distribution revenues (b):
Affiliated (TCEH)	$	998	$	208	$	821	$	243	$	894
Nonaffiliated		1,264		257		921		264		782
Total distribution revenues		2,262		465		1,742		507		1,676
Third-party transmission revenues		280		60		199		60		176
Other miscellaneous revenues		38		7		46		8		22
Total operating revenues	$	2,580	$	532	$	1,987	$	575	$	1,874

(a) SAIDI is the average number of minutes electric service is interrupted per consumer in a year. SAIFI is the average number of electric service interruptions per consumer in a year. CAIDI is the average duration in minutes per electric service interruption in a year. The statistics presented are based on the preceding twelve months’ data.

(b) Includes transition charge revenue associated with the issuance of securitization bonds totaling $140 million for the year ended December 31, 2008, $29 million for the period October 11, 2007 through December 31, 2007, $116 million for the period January 1, 2007 through October 10, 2007, $34 million for the three months ended December 31, 2006 and $117 million for the nine months ended September 30, 2006. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs.

Regulated Delivery Segment — Financial Results — 2008

Successor Period — Year Ended December 31, 2008

Operating revenues for 2008 of $2.6 billion reflected rate increases approved in 2006 and 2007 to recover ongoing investment in the transmission system and growth in points of delivery.

Operating costs for 2008 totaled $828 million, which included approximately $339 million in fees paid to other transmission providers and $125 million in property taxes. The balance of the costs consisted largely of employee and contractor costs to maintain and repair the transmission and distribution assets, including vegetation management.

Depreciation and amortization expense for 2008 of $492 million reflected ongoing investments in property, plant and equipment and included $145 million of ongoing regulatory asset amortization for which there are related revenues from transition charge billings.

SG&A expenses for 2008 totaled $164 million, which included administrative and general salaries and benefits and outsourced provider costs.

Franchise and revenue-based taxes for 2008 of $255 million reflected local franchise fees. State franchise taxes, which were previously reported with these taxes were replaced in 2007 by the Texas margin tax, which is reported in income taxes.

See Note 3 to Financial Statements for a discussion of the $860 million goodwill impairment charge recorded in the fourth quarter of 2008.

Other income for 2008 totaled $45 million, which included $44 million of accretion for an adjustment (discount) to regulatory assets resulting from purchase accounting. Other deductions for 2008 totaled $19 million, which included $13 million in costs associated with the 2006 cities rate settlement.

Interest income for 2008 totaled $45 million, which essentially consisted of interest income from TCEH with respect to Oncor’s generation-related regulatory assets securitized through the issuance of transition bonds by Oncor’s bankruptcy-remote financing subsidiary.

Interest expense and related charges for 2008 totaled $317 million, which reflected $5.363 billion in average borrowings at an average rate of 5.86%.

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Income tax expense on a pre-tax loss for 2008 totaled $221 million. Excluding the impact of the $860 million non-deductible goodwill impairment, the effective rate on pre-tax income was 37.2%. The effective rate of 37.2% as compared to the 35% federal statutory rate reflects state income taxes and the non-deductibility of losses on certain benefit plans, partially offset by the amortization of investment tax credits.

Net loss for 2008 totaled $486 million, primarily reflecting the effect of the impairment charge related to goodwill.

Regulated Delivery Segment — Financial Results — 2007 and 2006

Successor Period from October 11, 2007 through December 31, 2007 Compared to the Three Month Predecessor Period Ended December 31, 2006

Operating revenues decreased $43 million, or 7%, to $532 million in 2007. The ten fewer days in the 2007 period period resulted in $68 million in lower revenues. This decrease was partially offset by increased distribution tariffs to recover higher transmission costs, higher transmission revenues primarily due to rate increases to recover ongoing investment in the transmission system, the effect of weather-driven higher average electricity consumption and the impact of growth in points of delivery.

Operating costs decreased $9 million, or 5%, to $182 million in 2007. The ten fewer days in the 2007 period resulted in $24 million in lower costs. This decrease was partially offset by higher fees paid to other transmission entities and higher vegetation management expenses.

Depreciation and amortization decreased $21 million, or 18%, to $96 million in 2007. The ten fewer days in the 2007 period resulted in $12 million in lower costs.

SG&A expenses increased $6 million, or 15%, to $45 million in 2007. The ten fewer days in the 2007 period resulted in $2 million in lower costs. The increase primarily reflects increased incentive pay and benefit expense in 2007.

Franchise and revenue-based taxes decreased $11 million, or 15%, to $62 million in 2007. The ten fewer days in the 2007 period resulted in $8 million in lower costs. Included in franchise and revenue-based taxes are local franchise fees resulting from the 2006 cities rate settlement totaling $2 million for the period October 11, 2007 through December 31, 2007 and $1 million for the three months ended December 31, 2006.

Other income for 2007 totaled $11 million, which included $10 million of accretion for an adjustment (discount) to regulatory assets resulting from purchase accounting. Other deductions totaled $7 million and $11 million in 2007 and 2006, respectively, which included costs associated with the 2006 cities rate settlement of $6 million and $7 million, respectively.

Interest income decreased $3 million, or 20%, to $12 million in 2007. The ten fewer days in the 2007 period resulted in $2 million in lower interest income and contractual reimbursements from TCEH for transition bond interest expense declined as a result of the declining balance of such bonds.

Interest expense and related charges decreased by $3 million, or 4%, to $70 million in 2007. The ten fewer days in the 2007 period resulted in $9 million in lower expense. This decrease was largely offset by $5 million from higher average borrowings, largely to support the ongoing capital investment in the business, and $1 million from higher average interest rates.

Income tax expense for 2007 totaled $30 million and the effective tax rate was 32.3%. Income tax expense for 2006 totaled $24 million and the effective tax rate was 27.9%. The increase in the effective rate was primarily driven by adjustments to state income tax expense related to prior period state franchise tax returns.

Net income totaled $63 million in 2007 and $62 million in 2006.

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Predecessor Period from January 1, 2007 through October 10, 2007 Compared to the Nine Month Predecessor Period Ended September 30, 2006

Operating revenues increased $113 million, or 6%, to $1.987 billion in 2007. Of the increase, $68 million was attributed to the ten additional days in the 2007 period. The balance of the revenue increase reflected:

• $19 million for installation services related to equipment for a third party that will facilitate Oncor’s technology initiatives;

• $18 million from increased distribution tariffs to recover higher transmission costs, and

• $16 million in higher transmission revenues primarily due to rate increases approved in 2006 and 2007 to recover ongoing investment in the transmission system,

partially offset by,

• $9 million effect of lower average consumption due in part to cooler, below normal summer weather in 2007 and hotter than normal weather in 2006, net of the impact of increased points of delivery, and

• lower charges to REPs related to securitization bonds (offset by lower amortization of the related regulatory asset).

Operating costs increased $58 million, or 10%, to $637 million in 2007. Of the increase, $21 million was attributed to the ten additional days in the 2007 period. The balance of the increase reflected $19 million in higher fees paid to other transmission entities, $18 million in equipment installation costs for a third party that will facilitate Oncor’s technology initiatives, higher labor-related costs due to timing of equipment installation activities and increased labor cost primarily for restoration of service as a result of weather events, partially offset by lower vegetation management expenses.

Depreciation and amortization increased $7 million, or 2%, to $366 million in 2007 which was primarily due to the ten additional days in 2007 and ongoing investments in property, plant and equipment, partially offset by lower amortization of the regulatory assets associated with the securitization bonds (offset in revenue).

SG&A expenses increased $1 million, or less than 1%, to $139 million in 2007. The increase reflected expenses related to the rebranding of the Oncor Electric Delivery Company name and higher professional fees, partially offset by reduced labor and benefit costs due to lower staffing levels and the effect of executive severance expenses in 2006.

Franchise and revenue-based taxes increased $9 million, or 5%, to $198 million in 2007. The increase reflected higher franchise fees under the 2006 cities rate settlement partially offset by lower revenue-based taxes primarily driven by lower delivered volumes. Included in franchise and revenue-based taxes are local franchise fees resulting from the 2006 cities rate settlement totaling $5 million for the period January 1, 2007 through October 10, 2007 and $4 million for the nine months ended September 30, 2006.

Other income totaled $3 million in 2007 and $2 million in 2006. Other deductions totaled $27 million in 2007 and $13 million in 2006. The increase in other deductions was primarily due to higher costs associated with the 2006 cities rate settlement.

Interest expense increased $29 million, or 14%, to $242 million in 2007. Of this increase, $9 million was due to the ten additional days in the 2007 period. The balance of the increase reflected $14 million due to higher average borrowings, largely to support ongoing capital investment in the business, and $5 million due to higher average interest rates.

Income tax expense was $160 million in 2007 compared to $146 million in 2006. The effective income tax rate increased to 37.6% in 2007 from 34.1% in 2006. The increased rate was driven by higher taxes under the Texas margin tax, higher interest accrued related to uncertain tax positions and the effect of full amortization prior to 2007 of a regulatory liability associated with statutory tax rate changes.

Net income decreased $17 million, or 6%, to $265 million. This decrease was driven by higher costs associated with the 2006 cities rate settlement and a decline in delivered volumes due to lower average consumption.

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

The table below summarizes the changes in commodity contract assets and liabilities for the periods presented. The net changes in these assets and liabilities, excluding “fair value adjustments”, “other activity” and “reclassification” as described below, represent the pretax effect on earnings of positions in the commodity contract portfolio that are marked-to-market in net income (see Note 19 to Financial Statements). These positions represent both economic hedging and trading activities.

	Successor						Predecessor
	Year Ended December 31, 2008			October 11, 2007 through December 31, 2007			January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Commodity contract net asset (liability) at beginning of period	$	(1,917	)	$	(920	)	$	(23	)	$	(56	)
Settlements of positions (a) (c)		39			(87	)		(55	)		36
Unrealized mark-to-market valuations of unsettled positions (b) (c)		2,294			(1,469	)		(757	)		(3	)
Fair value adjustments at Merger closing date (d)		—			144			—			—
Reclassification at Merger closing date (e)		—			400			—			—
Other activity (f)		14			15			(85	)		—
Commodity contract net asset (liability) at end of period	$	430		$	(1,917	)	$	(920	)	$	(23	)

(a) Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and losses recognized in the settlement period).

(b) Primarily represents mark-to-market effects of positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”). Includes gains and losses recorded at contract inception dates (see Note 19 to the Financial Statements).

(c) Prior year amounts reflect reclassifications to include effects of positions entered into and settled within the same period. This change in presentation was made in connection with the 2008 reclassification of commodity hedging and trading activities discussed in Note 1 to the Financial Statements.

(d) Represents adjustments arising primarily from the adoption of SFAS 157 (largely nonperformance risk effect — see Note 24 to Financial Statements.)

(e) Represents reclassification of fair values of derivatives previously accounted for as cash flow hedges.

(f) These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration. Activity in the 2007 Predecessor period included $257 million (net of amounts settled of $7 million) in liabilities related to certain power sales agreements (see Note 19 to Financial Statements), net of a $102 million payment related to a structured economic hedge transaction in the long-term hedging program and $64 million in natural gas provided under physical gas exchange transactions.

Note: Of the $2.333 billion in unrealized net gains for the year ended December 31, 2008, $2.285 billion in net gains are reported in the income statement as net gain from commodity hedging and trading activities. The difference of $48 million in net gains relates to physically settled sales and purchase transactions, with $42 million in net gains reported in revenues and $6 million in net gains reported in fuel, purchased power costs and delivery fees, as required by accounting rules.

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In addition to the effect on net income of recording unrealized mark-to-market gains and losses that are reflected in the table above, similar effects arise in the recording of unrealized ineffectiveness gains and losses associated with commodity-related positions accounted for as cash flow hedges. These effects on net income, which include reversals of previously recorded unrealized ineffectiveness gains and losses to offset realized gains and losses upon settlement, are reflected in the balance sheet as changes in cash flow hedge and other derivative assets and liabilities (see Note 19 to Financial Statements). The total pretax effect of recording unrealized gains and losses in net income related to commodity contracts under SFAS 133 is summarized as follows:

	Successor						Predecessor
	Year Ended December 31, 2008			October 11, 2007 through December 31, 2007			January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Unrealized gains/(losses) related to contracts marked-to-market	$	2,333		$	(1,556	)	$	(812	)	$	33
Ineffectiveness gains/(losses) related to cash flow hedges (a)		(4	)		—			90			239
Total unrealized gains (losses) related to commodity contracts	$	2,329		$	(1,556	)	$	(722	)	$	272

(a) See Note 19 to Financial Statements.

Maturity Table — Following are the components of the net commodity contract asset at December 31, 2008:

	Successor Amount
Amount of net asset arising from mark-to-market accounting	$	459
Net receipts of natural gas under physical gas exchange transactions		(29	)
Net commodity contract asset	$	430

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The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of December 31, 2008, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

Source of fair value	Maturity dates of unrealized commodity contract asset at December 31, 2008
	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(167	)	$	(97	)	$	(6	)	$	—		$	(270	)
Prices provided by other external sources		427			324			66			—			817
Prices based on models		22			(75	)		(35	)		—			(88	)
Total	$	282		$	152		$	25		$	—		$	459
Percentage of total fair value		61	%		33	%		6	%		—	%		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. Over-the-counter quotes for power in ERCOT (excluding the West zone) generally extend through 2014 and over-the-counter quotes for natural gas generally extend through 2015, depending upon delivery point. The “prices based on models” category contains the value of all nonexchange 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 24 to Financial Statements for fair value disclosures required under SFAS 157 and for discussion of fair value measurements.

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COMPREHENSIVE INCOME

Cash flow hedge activity reported in other comprehensive income included (all amounts after-tax):

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Net increase (decrease) in fair value of cash flow hedges:
Commodities	$	(8	)	$	5		$	(288	)	$	598
Financing – interest rate swaps		(175	)		(182	)		—			—
		(183	)		(177	)		(288	)		598
Derivative value net losses (gains) reported in net income that relate to hedged transactions recognized in the period:
Commodities		11			—			(95	)		(53	)
Financing – interest rate swaps		111			—			6			8
		122			—			(89	)		(45	)
Total income (loss) effect of cash flow hedges reported in other comprehensive income	$	(61	)	$	(177	)	$	(377	)	$	553

All amounts included in accumulated other comprehensive income as of October 10, 2007, which totaled $34 million in net gains, were eliminated as part of purchase accounting.

EFH Corp. has historically used, and expects to continue to use, derivative instruments that are effective in offsetting future cash flow variability in interest rates and energy commodity prices. Amounts in accumulated other comprehensive income include (i) the value of unsettled transactions accounted for as cash flow hedges (for the effective portion), based on current market conditions, and (ii) the value of dedesignated and terminated cash flow hedges at the time of such dedesignation, less amounts reclassified to earnings as the original hedged transactions are recognized, unless the hedged transactions become probable of not occurring. The effects of the hedge will be recorded in the statement of income as the hedged transactions are actually settled and affect earnings. Also see Note 19 to Financial Statements.

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FINANCIAL CONDITION

Liquidity and Capital Resources

Cash Flows —Cash flows from operating, financing and investing activities included:

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Three Months Ended December 31, 2006			Nine Months Ended September 30, 2006
Cash flows — operating activities
Net income (loss)	$	(9,838	)	$	(1,360	)	$	723		$	475		$	2,077
Income from discontinued operations, net of tax effect		—			(1	)		(24	)		(6	)		(81	)
Income (loss) from continuing operations		(9,838	)		(1,361	)		699			469			1,996
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Depreciation and amortization		2,070			568			684			217			676
Deferred income tax expense (benefit) – net		(477	)		(736	)		(111	)		44			712
Impairment of goodwill and other intangible assets		9,842			—			—			—			—
Impairment of natural gas-fueled generation fleet		229			—			—			—			198
Net charges related to cancelled development of generation facilities		—			2			676			—			—
Unrealized net losses (gains) from mark-to-market valuations of commodity positions		(2,329	)		1,556			722			(58	)		(214	)
Unrealized net losses from mark-to-market valuations of interest rate swaps		1,477			—			—			—			—
Other, net (including customer refund accrual in late 2006)		22			16			52			137			37
Changes in operating assets and liabilities (including margin deposits)		509			(495	)		(457	)		100			640
Cash provided by (used in) operating activities	$	1,505		$	(450	)	$	2,265		$	909		$	4,045
Cash flows — financing activities
Equity financing from Sponsor Group and other investors	$	—		$	8,236		$	—		$	—		$	—
Net issuances, repayments and repurchases of borrowings		1,537			26,615			2,304			221			(975	)
Net issuances and repurchases of common stock		31			—			(12	)		(59	)		(773	)
Common stock dividends paid		—			—			(788	)		(189	)		(575	)
Debt discount, financing and reacquisition expenses		(21	)		(986	)		(17	)		(6	)		(17	)
Other		37			—			(93	)		53			(12	)
Cash provided by (used in) financing activities	$	1,584		$	33,865		$	1,394		$	20		$	(2,352	)
Cash flows — investing activities
Acquisition of EFH Corp.	$	—		$	(32,694	)	$	—		$	—		$	—
Capital expenditures, including purchases of mining-related assets and nuclear fuel		(2,978	)		(707	)		(2,517	)		(811	)		(1,486	)
Net proceeds from sale of minority interest		1,253			—			—			—			—
Proceeds from TCEH senior secured letter of credit facility deposited with bank		—			(1,250	)		—			—			—
Other		44			88			234			(148	)		(219	)
Cash used in investing activities	$	(1,681	)	$	(34,563	)	$	(2,283	)	$	(959	)	$	(1,705	)

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Year Ended December 31, 2008—Cash provided by operating activities totaled $1.505 billion, driven by cash earnings (net income adjusted for the noncash earnings items identified in the cash flow statement) and also reflecting receipts of margin deposits, which largely were used to repay TCEH Commodity Collateral Posting Facility borrowings related to natural gas hedges due to declining natural gas prices.

Successor Period from October 11, 2007 through December 31, 2007 compared to Three Months Ended December 31, 2006 – Cash used in operating activities totaled $450 million in the Successor period from October 11, 2007 through December 31, 2007 compared to cash provided by operating activities of $909 million in the three months ended December 31, 2006. The $1.359 billion decrease reflected:

• lower operating earnings after taking into account noncash items such as depreciation and amortization, deferred federal income tax expense, unrealized mark-to-market valuations and a charge related to a customer appreciation bonus, and

• a $598 million unfavorable change in net margin deposits which was largely funded by the Commodity Collateral Posting Facility, due to the effect of increases in forward natural gas prices on positions in the long-term hedging program.

Predecessor Period from January 1, 2007 through October 10, 2007 Compared to Nine Months Ended September 30, 2006—The $1.780 billion decrease in cash provided by operating activities reflected:

• a $1.149 billion unfavorable change in net margin deposits driven by the effect of higher forward natural gas prices on positions in the long-term hedging program, and

• lower operating earnings after taking into account noncash items such as depreciation and amortization, deferred federal income tax expense, unrealized mark-to-market valuations and charges related to cancelled development of generation facilities.

Recent capital spending trends reflect spending related to the development and construction of new generation facilities. Capital expenditures in 2008 totaled $1.914 billion in the Competitive Electric segment and $882 million in the Regulated Delivery segment.

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $460 million, $153 million, $50 million, $15 million and $48 million for the year ended December 31, 2008, the period from October 11, 2007 through December 31, 2007, the period from January 1, 2007 through October 10, 2007, the three months ended December 31, 2006 and the nine months ended September 30, 2006, respectively. For the 2007 and 2006 Predecessor periods, this difference represents amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent with industry practice. For the 2008 and 2007 Successor periods, this difference also represents amortization of intangible net assets and debt fair value discounts arising from purchase accounting that is reported in various other income statement line items including operating revenues, fuel and purchased power costs and interest expense.

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Debt Financing Activity—Activities related to short-term borrowings and long-term debt during the year ended December 31, 2008 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capital leases):

	Borrowings		Repayments and Repurchases
TCEH	$	1,685	$	853
EFC Holdings		—		7
EFH Corp.		—		208
Oncor		1,500		99
Total long-term		3,185		1,167
TCEH		462		—
Oncor		—		943
Total short-term (a)		462		943
Total	$	3,647	$	2,110
(a)    Short-term amounts represent net borrowings/repayments.

See Note 15 to Financial Statements for further detail of long-term debt and other financing arrangements.

EFH Corp. or its affiliates may from time to time purchase outstanding debt securities for cash in open market purchases, privately negotiated transactions or other transactions. EFH Corp. will evaluate any such transactions in light of market prices of the securities, taking into account its liquidity requirements and prospects for future access to capital, contractual restrictions and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material. No such purchases have occurred to date.

Available Liquidity — The following table summarizes changes in available liquidity for the year ended December 31, 2008.

	Available Liquidity
	December 31, 2008 (a)		December 31, 2007		Change
Cash and cash equivalents, excluding Oncor	$	1,564	$	259	$	1,305
Investment held in money market fund		142		—		142
TCEH Delayed Draw Term Loan Facility		522		1,950		(1,428	)
TCEH Revolving Credit Facility		1,767		2,636		(869	)
TCEH Letter of Credit Facility		490		9		481
Total (b)	$	4,485	$	4,854	$	(369	)
Cash and cash equivalents – Oncor		125		22		103
Oncor Revolving Credit Facility		1,508		720		788
Total	$	1,633	$	742	$	891

(a) The TCEH Revolving Credit Facility includes $144 million of undrawn commitments from the Lehman subsidiary that is only available from the fronting banks in the form of letters of credit.

(b) Pursuant to PUCT rules, TCEH is required to maintain available capacity under its credit facilities to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at December 31, 2008, the total availability under the TCEH credit facilities should be further reduced by $266 million.

Note: Available liquidity above does not include the potential amounts available from exercising the payment-in-kind (PIK) option on the EFH Corp. Toggle Notes and TCEH Toggle Notes, which for the remaining payment dates from November 2009 through November 2012, could add approximately $1.6 billion of liquidity.

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The decline in available liquidity, excluding Oncor, of $369 million in 2008 reflected borrowings to fund construction of the new generation facilities and use of cash for other capital expenditures, partially offset by proceeds from the sale of the minority interests in Oncor and reduced letters of credit issued driven by the effects of lower natural gas prices on commodity hedging positions.

The $142 million investments held in money market fund was received in January 2009.

The TCEH Delayed Draw Term Loan Facility is used to fund certain specified expenditures, principally related to the construction of the new generation facilities and the environmental retrofit program for existing facilities. The TCEH Revolving Credit Facility is used for working capital and other general corporate purposes. The TCEH Letter of Credit Facility is used for issuing letters of credit for general corporate purposes. The uncapped TCEH Commodity Collateral Posting Facility provides the collateral posting requirements for specified natural gas hedging transaction volumes. (See discussion below under “Liquidity Effects of Commodity Hedging and Trading Activities.”)

As of December 31, 2008, TCEH had borrowed $900 million under its Revolving Credit Facility, the majority of which was held as cash and cash equivalents and investment in money market fund. Although neither EFH Corp. nor TCEH has any immediate needs for the additional liquidity from the cash borrowings from the TCEH Revolving Credit Facility, the borrowings were made in September and October 2008 as a precautionary measure due to significant dislocation in the financial markets as evidenced by, among other matters, the bankruptcy filing by Lehman as well as a substantial widening of credit default swap spreads of other institutional banks, a significant increase in the LIBOR rate, a significant halt in commercial paper markets and a significant widening of TED (the price difference between 3-month T-Bill futures and 3-month Eurodollar futures) spreads (collectively, “Key Market Metrics”). TCEH anticipated repaying some or all of these borrowings upon seeing an improvement in financial market conditions. Given the enactment of federal legislation that is intended to support the solvency of institutional banks, significant improvement in each of the Key Market Metrics and the increased interest cost associated with having these borrowings remain outstanding, TCEH repaid a portion of the September and October 2008 borrowings. EFH Corp. and TCEH will continue to monitor financial market conditions, and TCEH anticipates repaying the remaining borrowings to the extent financial market conditions continue to improve. If, however, financial market conditions worsen, TCEH may continue to retain these borrowings and may borrow repaid funds. TCEH expects to maintain the cash proceeds from the borrowings in highly liquid short-term investments pending use for liquidity needs or repayment.

The Oncor Revolving Credit Facility is used for working capital and other general corporate purposes. Oncor may increase the commitments under its facility in any amount up to $500 million, subject to the satisfaction of certain conditions. Availability increased $930 million during 2008 primarily due to repayments made under such facility from the net proceeds of the issuance of $1.500 billion principal amount of fixed-rate senior notes as described in Note 15 to Financial Statements.

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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. In addition, under the terms of the Oncor Revolving Credit Facility, the commitments of the lenders to make loans to Oncor are several and not joint. Accordingly, if any lender fails to make loans to Oncor, Oncor’s available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the Oncor Revolving Credit Facility. See discussion below under “Bankruptcy Filing of Lehman Brothers Holdings Inc.”

See Note 15 to Financial Statements for additional discussion of the facilities.

Bankruptcy Filing of Lehman Brothers Holdings Inc.—In September 2008, Lehman Brothers Holdings Inc. (Lehman) filed for bankruptcy under the US Bankruptcy Code. EFH Corp. and its subsidiaries have business relationships with Lehman and its subsidiaries.

Subsidiaries of TCEH were counterparties with subsidiaries of Lehman with respect to wholesale energy marketing transactions, including natural gas hedging transactions that were part of EFH Corp.’s corporate hedging program. The obligations of these Lehman subsidiaries are guaranteed by Lehman, and the Lehman bankruptcy filing gave TCEH’s subsidiaries the right to terminate the transactions. TCEH’s subsidiaries provided notice to the Lehman subsidiaries terminating these transactions effective on September 15, 2008 (the “Termination Date”) pursuant to its rights under the master agreement for the transactions. As of the Termination Date, the TCEH subsidiaries’ direct net financial position with respect to these transactions was $26 million (excluding termination related costs), which was reserved for as a charge reported in other deductions in the three months ended September 30, 2008. EFH Corp.’s overall corporate hedging program was not materially impacted by this termination.

See “Available Liquidity” above and Note 15 to Financial Statements for the potential effects on the TCEH Senior Secured Facilities and the Oncor Revolving Credit Facility of Lehman’s bankruptcy filing.

Commodity Hedging and Trading Activities — With the tightening of credit markets, there has been some decline in the number of market participants in the energy commodities markets, resulting in less liquidity particularly in the ERCOT wholesale electricity market. Participation by financial institutions and other intermediaries (including investment banks) has declined. However, traditional counterparties with physical assets to hedge continue to participate in the markets. EFH Corp. continues to monitor liquidity and credit risk in the markets to assess any impacts on its overall hedging strategy.

Additional Financial Market Uncertainty Considerations— EFH Corp. has evaluated its investments held in trusts, including those that will be used by EFH Corp. to satisfy future obligations under pension and postretirement benefit plans. The recent substantial dislocation in the financial markets has caused a significant decline in the value of such investments, and a continuation or further dislocation in the markets could be material to EFH Corp.

As of December 31, 2008, EFH Corp. and its subsidiaries had no debt that was insured. TCEH has $204 million of tax-exempt long-term debt backed by $208 million in letters of credit expiring in 2014. If there is a loss of confidence in the creditworthiness of the letter of credit provider and TCEH were consequently unable to substitute letters of credit from an acceptable bank, TCEH could experience an increase in its interest expense.

Pension and OPEB Plan Funding — Pension and OPEB plan funding is expected to total $81 million and $22 million, respectively, in 2009. Based on the funded status of the pension plan at December 31, 2008, funding is expected to total approximately $665 million for the 2009 to 2013 period. Approximately 85% of this amount is expected to be funded by Oncor, consistent with its share of the pension liability. EFH Corp. made pension and OPEB contributions of $164 million and $40 million, respectively, in 2008.

See Note 22 to Financial Statements for more information regarding the pension and OPEB plans, including the funded status of the plans as of December 31, 2008.

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PIK Interest Election — EFH Corp. and TCEH have the option every six months until November 1, 2012, at their election, to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments. While EFH Corp. and TCEH have sufficient liquidity to meet their anticipated ongoing needs without use of this PIK feature, the companies elected to do so for the May 1, 2009 interest payment date as an efficient and cost-effective method to further enhance liquidity, in light of the substantial dislocation in the financial markets. Moreover, the incremental liquidity obtained by using the PIK feature of the toggle notes for this specific payment period more than offset the liquidity that was effectively lost as a result of the default by affiliates of Lehman under TCEH’s Senior Secured Facilities. In the future, EFH Corp. and TCEH will evaluate use of the PIK feature at each election period, taking into account market conditions and other relevant factors at such time.

EFH Corp. will make its May 2009 interest payment by using the PIK feature of the EFH Corp. Toggle Notes. The election will increase the interest rate on the toggle notes from 11.25% to 12.00% during the interest period covered by the PIK election and require EFH Corp. to issue an additional $150 million principal amount of EFH Corp. Toggle Notes on May 1, 2009. In addition, the election will increase liquidity by an amount equal to approximately $141 million, constituting the amount of cash interest that otherwise would have been payable on May 1, 2009, and increase the expected annual cash interest expense by approximately $17 million, constituting the additional cash interest that would be payable with respect to the $150 million of additional toggle notes.

Similarly, TCEH will make its May 2009 interest payment by using the PIK feature of the TCEH Toggle Notes. The election will increase the interest rate on the TCEH Toggle Notes from 10.50% to 11.25% during the interest period covered by the PIK election and require TCEH to issue an additional approximately $98.5 million principal amount of TCEH Toggle Notes on May 1, 2009. In addition, the election will increase liquidity by an amount equal to approximately $92 million, constituting the amount of cash interest that otherwise would have been payable on May 1, 2009, and increase the expected annual cash interest expense by approximately $10 million, constituting the additional cash interest that would be payable with respect to the $98.5 million of additional toggle notes.

Liquidity Needs, Including Capital Expenditures —Capital expenditures, including capitalized interest, for 2009 are expected to total approximately $2.6 billion and include:

• $875 million for investment in Oncor’s transmission and distribution infrastructure and $90 million for Oncor’s investment related to the CREZ Transmission Plan;

• $1.6 billion for investments in TCEH generation facilities, including:

• approximately $700 million related to the construction of one generation unit at Sandow and two generation units and mine development at Oak Grove;

• approximately $800 million for major maintenance, primarily in existing generation operations, and

• approximately $100 million for environmental expenditures related to existing generation units.

Because its businesses are capital intensive, EFH Corp. expects 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 its credit facilities. The inability to raise capital on favorable terms or failure of counterparties to perform under credit, hedging or other financial agreements, particularly considering the current uncertainty in the financial markets, could impact EFH Corp.’s ability to sustain and grow its businesses and would likely increase capital costs. EFH Corp. expects cash flows from operations combined with availability under its credit facilities discussed in Note 15 to Financial Statements to provide sufficient liquidity to fund its current obligations, projected working capital requirements, any restructuring obligations and capital spending for a period that includes the next twelve months.

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Liquidity Effects of Commodity Hedging and Trading Activities — Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. EFH Corp. and its subsidiaries use cash and letters of credit and other collateral structures to satisfy such collateral obligations. In addition, TCEH’s Commodity Collateral Posting Facility, an uncapped senior secured revolving credit facility, funds the cash collateral posting requirements for a significant portion of the positions in EFH Corp.’s long-term hedging program not otherwise secured by a first-lien in the assets of TCEH. The aggregate principal amount of this 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 TCEH Commodity Collateral Posting Facility, at January 30, 2009, more than 95% of EFH Corp.’s 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 EFH Corp.’s liquidity exposure associated with collateral requirements for those hedging transactions. See Note 15 to Financial Statements for more information about this facility.

As of December 31, 2008, subsidiaries of EFH Corp. have received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $317 million in cash has been received from counterparties for exchange cleared transactions (including initial margin), as compared to $79 million posted as of December 31, 2007,

• $402 million in cash has been received from counterparties for over-the-counter and other non-exchanged cleared transactions, as compared to $429 million posted as of December 31, 2007, and

• $342 million in letters of credit have been posted with counterparties, as compared to $592 million posted as of December 31, 2007.

Borrowings under the TCEH Commodity Collateral Posting Facility funded the substantial majority of the above cash postings. The posted letters of credit were largely supported by restricted cash borrowed under the TCEH Letter of Credit Facility. See Notes 15 and 28 to Financial Statements.

With respect to exchange cleared transactions, these 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. With respect to cash collateral that is received, such cash collateral is either used by EFH Corp. and its subsidiaries for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or it is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. On over-the-counter transactions, such 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 EFH Corp.’s liquidity in the event that it was not restricted. As of December 31, 2008, cash collateral of $4 million was restricted. See Note 28 to Financial Statements regarding restricted cash.

With the long-term hedging program, increases in natural gas prices result in increased cash collateral and letter of credit margin requirements. As a representative example, as of January 30, 2009, for each $1.00 per MMBtu increase in forward natural gas prices across the period from 2009 through 2014, EFH Corp.’s cash collateral posting requirements associated with its long-term hedging program would increase by approximately $0.8 billion, essentially all of which would be funded by the TCEH Commodity Collateral Posting Facility.

Interest Rate Swap Transactions —In January and February 2009, TCEH entered into interest rate basis swap transactions pursuant to which payments of the floating interest rates at three-month LIBOR on an aggregate of $5 billion of senior secured term loans of TCEH were exchanged for floating interest rates at one-month LIBOR plus spreads ranging from 0.201% to 0.353%. See Note 15 to Financial Statements for TCEH interest rate swaps entered into as of December 31, 2008.

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Distributions from Oncor —Until December 31, 2012, distributions paid by Oncor are limited to an amount not to exceed Oncor’s net income determined in accordance with GAAP, subject to certain defined adjustments. Such adjustments include a reduction for the $72 million ($46 million after-tax) one-time refund to customers in September 2008. The liability for the refund was recorded in purchase accounting. See discussion above under “Significant Activities and Events – Oncor Refund to Customers.” Distributions are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. The net proceeds of $1.253 billion received by Oncor from its November 2008 sale of minority equity interests to Texas Transmission and certain members of Oncor’s management were excluded from these distribution limitations.

Oncor has jointly filed a transmission proposal with the PUCT indicating its interest in constructing and operating transmission facilities related to Competitive Renewable Energy Zones. See discussion below under “Regulation and Rates – Oncor Matters with the PUCT.” Oncor was awarded construction and operation of approximately $1.3 billion of such facilities, and EFH Corp. expects that Oncor may retain its available cash to fund such construction instead of paying distributions to EFH Corp.

Income Tax Refunds/Payments —In 2008, EFH Corp. received net federal income tax refunds of $229 million, including a $98 million refund in September 2008 related to 2007 tax payments in connection with the filing of its 2007 federal income tax return and an additional refund of $142 million in October 2008 as a result of filing for a net operating loss carryback to the 2006 tax year. Additionally, in February 2009, EFH Corp. received a refund totaling $98 million in income taxes and related interest related to IRS audits of 1993 and 1994 tax returns (see Note 10 to Financial Statements). EFH Corp. does not expect any refunds or payments in 2009 related to the filing of 2008 tax returns. Federal income tax payments totaled $257 million in 2007 and $220 million in 2006.

As discussed in Note 10 to Financial Statements, EFH Corp. assesses uncertain tax positions under a “more-likely-than-not” standard. Should such assessments change, a material balance now recorded as accumulated deferred income taxes could be reclassified to a liability, and material cash tax payments could be accelerated. EFH Corp. cannot reasonably estimate the ultimate amounts and timing of tax payments associated with uncertain tax positions, but expects that no material federal income tax payments will be made in 2009.

Sale of Accounts Receivable — Certain subsidiaries of EFH Corp. participate in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with SFAS 140. Under the program, subsidiaries of EFH Corp. (originators) sell 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 special purpose entities established by financial institutions. All new trade receivables under the program generated by the originators are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $416 million and $363 million at December 31, 2008 and 2007, respectively. See Note 14 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 a reduction of funding available under the program.

Capitalization — The capitalization ratios of EFH Corp. consisted of 109.5% and 85.2% long-term debt, less amounts due currently, and (9.5)% and 14.8% common stock equity, at December 31, 2008 and 2007, respectively. Total debt to capitalization, including short-term debt, was 109.1% and 85.9% at December 31, 2008 and 2007, respectively.

Covenants and Restrictions under Financing Arrangements —Each of the TCEH Senior Secured Facilities and indentures governing the TCEH Notes and the EFH Corp. Notes contains covenants that could have a material impact on the liquidity and operations of EFH Corp. and its subsidiaries. A brief description of certain of these covenants is provided below. See also Note 15 to Financial Statements for additional discussion of the covenants contained in these financing arrangements. Certain series of TCEH’s pollution control revenue bonds, which were remarketed in June 2008, include covenants similar to those discussed below regarding the TCEH Notes.

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When the term “Adjusted EBITDA” (see Glossary) is referenced in the covenant description below, it is a reference to, and generally synonymous with, the term “Consolidated EBITDA” that is used in the TCEH Senior Secured Facilities and a reference to, and generally synonymous with, the term “EBITDA” that is used in the indenture governing the EFH Corp. Notes. Further, the indenture provides that Oncor results be included in Adjusted EBITDA when used in connection with making restricted payments and investments other than payments to the Sponsor Group, but that the Oncor results be excluded and distributions received from Oncor be included when used in connection with incurrences of indebtedness. Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. Notes) for the year ended December 31, 2008 totaled $4.6 billion for EFH Corp. See Exhibit 99(b) and 99(c) for a reconciliation of net income to Adjusted EBITDA for EFH Corp. and TCEH, respectively, for the years ended December 31, 2008 and 2007.

Maintenance Covenant—Under the TCEH Senior Secured Facilities, TCEH and its restricted subsidiaries are required to maintain a consolidated secured debt to Adjusted EBITDA ratio (as defined in the TCEH Senior Secured Facilities) measured over a rolling four-quarter measurement period, which must not exceed 7.25 to 1.00 for the measurement period ending December 31, 2008, declining over time to 5.75 to 1.00 for the measurement periods ending March 31, 2014 and thereafter. In the event that TCEH fails to comply with this ratio, it generally has the right to cure its non-compliance by soliciting a cash investment in an amount necessary to become compliant. The ratio for the period ended December 31, 2008 was 4.77 to 1.00.

Debt Incurrence Covenants — Under the indenture governing the EFH Corp. Notes, EFH Corp. and its restricted subsidiaries (other than TCEH and its restricted subsidiaries) are not permitted to incur indebtedness or issue certain classes of preferred stock unless, on a pro forma basis, after giving effect to such incurrence or issuance, the fixed charge coverage ratio (as defined in the EFH Corp. indenture) on a consolidated basis for EFH Corp. and its restricted subsidiaries is at least 2.0 to 1.0 or such incurrence or issuance is otherwise permitted by specified exceptions in the indenture. The fixed charge coverage ratio is generally defined as the ratio of Adjusted EBITDA of EFH Corp. to fixed charges of EFH Corp., in each case on a consolidated basis but excluding Oncor. The fixed charge coverage ratio for EFH Corp. was 1.5 to 1.0 at December 31, 2008. In addition, under this indenture, TCEH and its restricted subsidiaries are not permitted to incur indebtedness or issue certain classes of preferred stock unless, on a pro forma basis, after giving effect to such incurrence or issuance, the fixed charge coverage ratio (as defined in the indenture) on a consolidated basis for TCEH and its restricted subsidiaries is at least 2.0 to 1.0 or such incurrence or issuance is otherwise permitted by specified exceptions in the indenture. The fixed charge coverage ratio for that purpose is generally defined as the ratio of Adjusted EBITDA of TCEH to fixed charges of TCEH, in each case, on a consolidated basis. The fixed charge coverage ratio for TCEH as of December 31, 2008 was 1.3 to 1.0.

Under the TCEH Senior Secured Facilities, TCEH and its restricted subsidiaries are generally not permitted to incur indebtedness unless, on a pro forma basis, after giving effect to such incurrence, the Adjusted EBITDA to consolidated interest expense ratio (as defined in the TCEH Senior Secured Facilities) is at least 2.0 to 1.0 or such incurrence is otherwise permitted by specified exceptions in the TCEH Senior Secured Facilities. This ratio was 1.3 to 1.0 for the year ended December 31, 2008.

Under the indenture governing the TCEH Notes, TCEH and its restricted subsidiaries are not permitted to incur indebtedness or issue certain classes of preferred stock unless, on a pro forma basis, after giving effect to such incurrence or issuance, the fixed charge coverage ratio (as defined in such indenture) on a consolidated basis for TCEH and its restricted subsidiaries is at least 2.0 to 1.0 or such incurrence or issuance is otherwise permitted by specified exceptions in such indenture. The fixed charge coverage ratio is generally defined as the ratio of Adjusted EBITDA of TCEH to fixed charges of TCEH, in each case, on a consolidated basis. The ratio was 1.3 to 1.0 for the year ended December 31, 2008.

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Restricted Payments/Limitation on Investments — Under the indenture governing the EFH Corp. Notes, EFH Corp. and its restricted subsidiaries have limitations, subject to certain exceptions, on making restricted payments (as defined in the indenture), including cash dividends, equity repurchases, subordinated debt repayments and investments, unless the amount of such restricted payments is less than a formula based on 50% of consolidated net income (as defined in such indenture) and unless a fixed charge coverage ratio (as defined in such indenture), on a pro forma basis, after giving effect to such restricted payment, is at least 2.0 to 1.0 (or 2.0 to 1.0 of TCEH in the case of certain restricted payments by TCEH and its restricted subsidiaries) or as such restricted payment is otherwise permitted by specified exceptions in the indenture. The fixed charge coverage ratio for this purpose is generally defined as the fixed charge coverage ratio of EFH Corp. and all of its restricted subsidiaries, including Oncor Holdings and its subsidiaries as restricted subsidiaries for purposes of such calculation, and was 1.3 to 1.0 as of December 31, 2008. However, in the case of payments to the Sponsor Group, the fixed charge coverage ratio for this purpose is defined as the fixed charge coverage ratio of EFH Corp. and its restricted subsidiaries (but not including Oncor Holdings and its subsidiaries as restricted subsidiaries for purposes of such calculation) and was 1.5 to 1.0 as of December 31, 2008. Notwithstanding any other provisions of the indenture, EFH Corp. and its restricted subsidiaries may not pay any dividends or other returns to Texas Holdings unless, on a pro forma basis, after giving effect to such payment, the consolidated leverage ratio of EFH Corp. is equal to or less than 7.0 to 1.0. The consolidated leverage ratio is generally defined as the ratio of consolidated total indebtedness (as defined in the indenture) of EFH Corp. to Adjusted EBITDA of EFH Corp., in each case, on a consolidated basis, excluding Oncor Holdings and its subsidiaries, and was 6.9 to 1.0 as of December 31, 2008.

Under the terms of the TCEH Senior Secured Facilities, TCEH is required, commencing with and including the year ended December 31, 2008, to prepay within 90 days after the end of each such year, principal amounts of term loans with certain excess cash flows as defined in the indenture. TCEH realized no excess cash flows for the year ended December 31, 2008; therefore, no such prepayments are required to be made in 2009 under these provisions.

Under the TCEH Senior Secured Facilities and indenture governing the TCEH Notes, TCEH and its restricted subsidiaries have limitations (subject to certain exceptions) on making restricted payments or investments (as defined in the applicable debt agreements), including certain dividends, equity repurchases, debt repayments, extensions of credit and certain types of investments.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain financing arrangements of subsidiaries of EFH Corp. contain financial covenants that require maintenance of leverage ratios and/or contain a minimum net worth covenant. As of December 31, 2008, EFH Corp.’s subsidiaries were in compliance with all such applicable covenants.

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Credit Ratings —The rating agencies assign issuer credit ratings for EFH Corp. and its subsidiaries. The issuer credit ratings as of February 20, 2009 for EFH Corp. and its subsidiaries, except for Oncor, are B-, B2 and B by S&P, Moody’s and Fitch, respectively. The issuer credit ratings for Oncor are BBB+ and BBB- by S&P and Fitch, respectively.

Additionally, the rating agencies assign credit ratings on certain debt securities issued by EFH Corp. and its subsidiaries. The credit ratings assigned for debt securities issued by EFH Corp. and certain of its subsidiaries as of February 20, 2009 are presented below:

	S&P	Moody’s	Fitch
EFH Corp. (Senior Unsecured) (a)	B-	B3	B+
EFH Corp. (Unsecured)	CCC	Caa1	CCC+
EFC Holdings (Senior Unsecured)	CCC	Caa1	CCC+
TCEH (Senior Secured)	B+	Ba3	BB
TCEH (Senior Unsecured) (b)	CCC	B3	B+
TCEH (Unsecured)	CCC	Caa1	B-
Oncor (Senior Secured) (c)	BBB+	Baa3	BBB
Oncor (Senior Unsecured) (c)	BBB+	Baa3	BBB-
(a)    EFH Corp. Cash Pay Notes and EFH Corp. Toggle Notes (b)    TCEH Cash Pay Notes and TCEH Toggle Notes (c)    All of Oncor’s long-term debt is secured by a first priority lien and is considered senior secured debt.

S&P and Fitch have placed the ratings for EFH Corp. and its subsidiaries on “stable outlook.” In November 2008, Moody’s announced that it changed the rating outlook for EFH Corp. and TCEH to negative from stable stating that the change was primarily related to the decision to elect the PIK interest option on the EFH Corp. Toggle Notes and the TCEH Toggle Notes for the interest due on May 1, 2009. Furthermore, in February 2009, Moody’s placed the ratings for EFH Corp. and TCEH on review for possible downgrade. Moody’s ratings outlook for Oncor remains stable.

In November 2008, Oncor sold additional equity interests resulting in an unaffiliated investor group acquiring a 19.75% minority stake in Oncor. In connection with Oncor’s execution of the agreement, S&P upgraded Oncor’s issuer credit rating and Oncor’s long-term debt ratings by two notches from BBB- to BBB+, and Moody’s upgraded Oncor’s long-term debt ratings by one notch from Ba1 to Baa3. In conjunction with the Moody’s upgrade, Moody’s withdrew its issuer credit rating of Ba1 previously assigned to Oncor. As a matter of practice, Moody’s does not assign issuer credit ratings for investment grade utility companies. See Note 1 to Financial Statements for additional information on the minority interests sale.

A rating reflects only the view of a rating agency, and is not a recommendation to buy, sell or hold securities. Ratings can be revised upward or downward at any time by a rating agency if such rating agency decides that circumstances warrant such a change.

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, 2008, counterparties to those contracts could have required TCEH to post up to an aggregate of $87 million in additional collateral. This amount largely represents the below market terms of these contracts as of December 31, 2008; 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 the previous downgrade of TCEH’s credit rating to below investment grade, 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. Based on requests to post collateral support from utilities that have been received by TCEH and its subsidiaries as of December 31, 2008, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $42 million, with $13 million of this amount posted for the benefit of Oncor.

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The PUCT has rules in place to assure adequate credit worthiness of any REP. Under these rules, TCEH maintains availability under its credit facilities of an amount no less than the aggregate amount of customer deposits and any advanced payments received from customers, and other cash resources required by PUCT rules. As of December 31, 2008, the amount of customer deposits received from customers held by TCEH’s REP subsidiaries and other required cash resources totaled approximately $266 million.

The RRC has rules in place to assure adequate credit worthiness of parties that have mining reclamation obligations. Under these rules, should the RRC determine that the credit worthiness of Luminant Generation Company LLC is not sufficient to support Luminant’s reclamation obligations, TCEH may be required to post cash or letter of credit collateral support in an amount currently estimated to be approximately $600 million to $800 million. This amount would vary depending upon numerous factors, including Luminant Generation Company LLC’s credit worthiness and the level of mining reclamation obligations.

ERCOT also has rules in place to assure adequate credit worthiness of parties that schedule power on the ERCOT System. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $33 million as of December 31, 2008 (which is subject to weekly 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 is required to post a letter of credit in an amount equal to $170 million to secure TXU Energy’s payment obligations to Oncor if two or more of Oncor’s credit ratings are below investment grade.

Other arrangements of EFH Corp. and its subsidiaries, including Oncor’s credit facility, the accounts receivable securitization program (see Note 14 to Financial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the credit ratings of certain EFH Corp. subsidiaries.

In the event that any or all of the additional collateral requirements discussed above are triggered, EFH Corp. believes it will have adequate liquidity to satisfy such requirements.

Material Cross Default Provisions — Certain financing arrangements contain provisions that may 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” provisions.

A default by TCEH or any restricted subsidiary in respect of indebtedness, excluding indebtedness relating to the sale of receivables 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 may cause the maturity of outstanding balances ($22.1 billion at January 30, 2009) under such facilities to be accelerated.

The indenture governing the $6.75 billion of TCEH Notes contains a cross acceleration provision where a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of TCEH and any of its restricted subsidiaries in the aggregate amount equal to or greater than $250 million may cause the acceleration of the TCEH Notes.

Under the terms of a TCEH rail car master equipment lease with approximately $49 million in remaining lease principal payments as of December 31, 2008, 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.

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Under the terms of a TCEH rail car master lease with approximately $56 million in remaining lease payments as of December 31, 2008, if obligations of TCEH in the aggregate in excess of $200 million for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements have been 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 indenture governing the $4.5 billion of EFH Corp. Notes contains a cross acceleration provision where a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of EFH Corp. and any of its restricted subsidiaries in the aggregate amount equal to or greater than $250 million may cause the acceleration of the EFH Corp. Notes.

The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that applies in the aggregate to the originators, any parent guarantor of an originator or TCEH acting as collection agent under the program. TXU Receivables Company and EFH Corporate Services Company, as collection agent, in the aggregate have a cross default threshold of $50,000. If any of the aforementioned defaults on indebtedness of the applicable threshold were to occur, the program could terminate.

EFH Corp. and its subsidiaries 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 EFH Corp. or those subsidiaries were to default under an obligation in respect of borrowings in excess of thresholds, which vary, stated in the contracts. The entities whose default would trigger cross default vary depending on the contract.

Each of TCEH’s natural gas hedging 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), then each counterparty under these hedging agreements would have the right to terminate its hedge agreement with TCEH and require all outstanding obligations under such agreement to be settled.

In the event of a default by TCEH relating to indebtedness in an amount equal to or greater than $200 million that results in the acceleration of such debt, then each counterparty under TCEH’s interest rate swap agreements with a notional value totaling $32 billion at January 30, 2009 would have the right to terminate its interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.

A default by Oncor or any subsidiary thereof in respect of indebtedness in a principal amount in excess of $50 million may result in a cross default under its credit facility. Under this facility such a default may cause the maturity of outstanding balances ($337 million at January 30, 2009) under such facility to be accelerated.

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

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Long-Term Contractual Obligations and Commitments— The following table summarizes EFH Corp.’s contractual cash obligations as of December 31, 2008 (see Note 15 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)	$	371	$	1,094	$	2,117	$	38,325	$	41,907
Long-term debt – interest (b)		3,141		6,626		6,284		9,786		25,837
Operating and capital leases (c)		90		214		123		398		825
Obligations under commodity purchase and services agreements (d)		1,735		1,476		598		603		4,412
Total contractual cash obligations (e)	$	5,337	$	9,410	$	9,122	$	49,112	$	72,981

(a) Excludes capital lease obligations, unamortized discounts and fair value premiums and discounts related to purchase accounting. Also excludes $249 million of additional principal amount of notes to be issued in May 2009 and due in 2016 and 2017, reflecting the election of the PIK feature on toggle notes as discussed above under PIK Interest Election.

(b) Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interest rate swaps are calculated based on interest rates in effect at December 31, 2008.

(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 assumed the year-end 2008 price remained in effect for all periods except where contractual price adjustment or index-based prices were specified.

(e) Table does not include estimated 2009 funding of the pension and other postretirement benefits plans totaling approximately $103 million. Funding for the pension plan is expected to total approximately $665 million for the 2009 to 2013 period as discussed above under “Pension and OPEBs Plan Funding.” It also does not include cancellable contracts associated with the construction of new generation facilities with obligations totaling approximately $550 million through 2010. See Note 16 to Financial Statements.

The following contractual obligations were excluded from the table above:

• contracts between affiliated entities and intercompany debt;

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

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

• employment contracts with management, and

• liabilities related to uncertain tax positions totaling $1.6 billion discussed in Note 10 to Financial Statements as the ultimate timing of payment is not known.

Hearings on CREZ Transmission Plan proposals were held in December 2008. At a January 2009 open meeting, the PUCT assigned approximately $1.3 billion of CREZ construction projects to Oncor. Oncor anticipates that a written order reflecting the PUCT’s decisions will be entered in the first quarter of 2009. Oncor expects capital expenditures related to CREZ transmission facilities to be approximately $90 million in 2009 with additional expenditures through 2012. These amounts are not included in the table above.

Guarantees — See Note 16 to Financial Statements for details of guarantees.

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OFF–BALANCE SHEET ARRANGEMENTS

See discussion above under “Sale of Accounts Receivable” and in Note 14 to Financial Statements.

Also see Note 16 to Financial Statements regarding guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 16 to Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

See Note 1 to Financial Statements for a discussion of changes in accounting standards.

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REGULATION AND RATES

2009 Texas Legislative Session

The Texas Legislature convened in its regular biennial session beginning January 13, 2009. The session will conclude June 1, 2009. EFH Corp. is actively monitoring and providing input regarding legislation that could impact its operations. EFH Corp. is unable to predict the outcome of the 2009 legislative process or its impact, if any, on its financial position, results of operations or cash flows.

Regulatory Investigations and Reviews

See Note 16 to Financial Statements.

Certification of REPs

In October 2008, the PUCT proposed a replacement of the rule relating to Certification of Retail Electric Providers. The proposed new rule is expected to strengthen the certification requirements for REPs in order to better protect customers, transmission and distribution utilities (TDUs), and other REPs from the insolvency and other harmful conditions and activities of REPs. The new rule would be considered a competition rule and thus be subject to judicial review as specified in PURA. The new rule proposes, among other things, increased creditworthiness requirements and financial reporting for REPs, additional customer protection requirements, deposit requirements to TDUs, and regulatory asset consideration for bad debt expenses. The PUCT is expected to finalize the new rule in the first quarter of 2009. EFH Corp. cannot predict the final outcome of this proposed rule.

Wholesale Market Design

In August 2003, the PUCT adopted a rule that, when implemented, will alter the wholesale market design in the ERCOT market. The rule requires ERCOT to:

• use a stakeholder process to develop a new wholesale market model;

• operate a voluntary day-ahead energy market;

• directly assign all congestion rents to the resources that caused the congestion;

• use nodal energy prices for resources;

• provide information for energy trading hubs by aggregating nodes;

• use zonal prices for loads, and

• provide congestion revenue rights (but not physical rights).

ERCOT currently has a zonal wholesale market structure consisting of four geographic zones. The proposed location-based congestion-management market is referred to as a “nodal” market because wholesale pricing would differ across the various nodes on the transmission grid. The implementation of a nodal market is being done in conjunction with transmission improvements designed to reduce current congestion. In 2006, the PUCT approved a set of Nodal Protocols that was filed by ERCOT and describes the operation of a wholesale nodal market, and set an implementation date of no later than January 1, 2009. ERCOT has delayed the start of the nodal market beyond the January 1, 2009 implementation date. Pursuant to a request from the PUCT, ERCOT announced in November 2008 a new preliminary schedule for the implementation of the nodal market by December 2010. Additionally, pursuant to a request from the PUCT, ERCOT prepared a revised cost-benefit analysis for implementation of a nodal market design that showed a net present value of total system cost savings of $520 million compared to a net present value of $222 million of going forward costs for a nodal market design. In accordance with a PUCT order, ERCOT included a preliminary Nodal Program Integrated Project Schedule as part of the overall nodal budget filing with the PUCT in February 2009 as discussed immediately below.

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In August 2006, the PUCT adopted an interim order approving ERCOT’s application for a surcharge imposed on all Qualified Scheduling Entities in the ERCOT market (including subsidiaries of TCEH) for the purpose of financing 38% of ERCOT’s expected nodal implementation costs. The surcharge took effect in October 2006. Additionally, in May 2008, the PUCT approved an increase in the surcharge. In November 2008, ERCOT filed a request with the PUCT for approval of an interim increase in the nodal surcharge from $0.169 per MWh to $0.38 per MWh. At the PUCT’s Open Meeting on January 14, 2009, the PUCT voted to extend the existing $0.169 per MWh nodal surcharge through the end of February 2009. ERCOT submitted a revised not to exceed budget of $658.7 million with the PUCT in February 2009, up from the initial nodal budget of $363.5 million. At the PUCT open meeting on February 26, 2009, the PUCT commissioners voted to extend the ERCOT nodal program until March 31, 2009, while maintaining the existing nodal surcharge of $0.169 per MWh. The PUCT directed ERCOT to submit a filing for approval of the full nodal surcharge, budget and schedule by March 31, 2009. At the current level of the nodal surcharge, EFH Corp. expects that the annual impact of the surcharge would be approximately $10 to $11 million in additional expenses; however, EFH Corp. is unable to predict the ultimate impact of the proposed nodal wholesale market design on its operations or financial results.

Environmental Regulations

See discussion in Note 3 to Financial Statements regarding the invalidation of the EPA’s Clean Air Interstate Rule and the related impairment of intangible assets representing NOx and SO₂ emission allowances.

Oncor Matters with the PUCT

Stipulation Approved by the PUCT—In April 2008, the PUCT entered an order, which became final in June 2008, approving the terms of a stipulation relating to the filing in 2007 by Oncor and Texas Holdings of a Merger-related Joint Report and Application with the PUCT pursuant to Section 14.101 (b) of PURA and PUCT Substantive Rule 25.75. The stipulation required the filing of a rate case by Oncor no later than July 1, 2008 based on a test year ended December 31, 2007. Oncor filed the rate case with the PUCT in June 2008. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200^th District Court of Travis County, Texas. Oncor was named a defendant and intends to vigorously defend the appeal.

Rate Case—In June 2008, Oncor filed for a rate review with the PUCT (Docket No. 35717) and 204 cities, as required by the order approving the stipulation discussed above. If approved as requested, this review would result in an aggregate annual rate increase of approximately $253 million (adjusted from $275 million as reflected in Oncor’s initial filing), the majority of which relates to increased depreciation expense due to capital investments and recovery of costs that have been recorded as regulatory assets. A hearing on the merits concluded in February 2009. Resolution of Oncor’s proposed rate increase is expected to occur in the summer of 2009.

Advanced Meter Rulemaking — In 2005, the Texas Legislature passed legislation that authorized electric utilities to implement a surcharge to recover costs incurred in deploying advanced metering and meter information networks. Benefits of the advanced metering installation include improved safety, on-demand meter reading, enhanced outage identification and restoration and system monitoring of voltages. In 2007, the PUCT issued its advanced metering rule to implement this legislation. This rule outlined the minimum required functionality for an electric utility’s advanced metering systems to qualify for cost recovery under a surcharge. Subsequent to the issuance of the rule, the PUCT opened an implementation proceeding for market participants to fine-tune the rule requirements, address the impacts of advanced metering deployment on retail and wholesale markets in ERCOT, and help ensure that retail customers receive benefits from advanced metering deployment. The implementation proceeding is expected to conclude by the end of the first quarter of 2009.

Advanced Metering Deployment Surcharge Filing— In May 2008, Oncor filed with the PUCT (Docket No. 35718) a description and request for approval of its proposed advanced metering system deployment plan and its proposed surcharge for the recovery of its estimated future investment for advanced metering deployment. Oncor’s plan provides for the full deployment of over three million advanced meters by the end of 2012 to all residential and most non-residential retail electricity customers in Oncor’s service area. Oncor installed approximately 5,000 advanced meters in a pilot program in the three months ended June 30, 2008, and deployed approximately 35,000 additional advanced meters in the fourth quarter of 2008.

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In August 2008, a settlement was reached with the majority of the parties to this surcharge filing. The settlement includes the following major provisions (the comparisons are against amounts filed in the original request):

• a surcharge beginning on January 1, 2009 and continuing for 11 years;

• a total revenue requirement over the surcharge period of $1.035 billion (reduced from $1.069 billion);

• estimated capital expenditures for advanced metering facilities of $686 million (reduced from $690 million);

• related operation and maintenance expenses for the surcharge period of $153 million (increased from $148 million);

• $28 million of additional savings (in addition to the $176 million in the original filing), and

• an advanced metering cost recovery factor of $2.21 per month per residential retail customer (reduced from $2.29 per month) and varying from $2.42 to $5.21 per month for non-residential retail customers (reduced from $2.49 to $5.35 per month).

An order approving the settlement was issued by the PUCT in August 2008 and became final in September 2008. Oncor began billing the advanced metering surcharge in the January 2009 billing month cycle. Oncor may, through subsequent reconciliation proceedings, request recovery of additional costs that are reasonable and necessary. While there is a presumption that costs spent in accordance with a plan approved by the PUCT are reasonable and necessary, recovery of any costs that are found not to have been spent or properly allocated, or not to be reasonable or necessary, must be refunded.

Prior to the PUCT issuance of rules for minimum required functionality for advanced metering systems, Oncor installed approximately 600,000 automated meters in its service territory at a capital cost of approximately $125 million. These meters are not part of the surcharge request, and Oncor is seeking recovery of the incremental costs of these meters in its general rate case discussed above.

Oncor Energy Efficiency Cost Recovery Filing—In June 2008, Oncor filed with the PUCT a Request for Approval of Energy Efficiency Cost Recovery Factor (Docket No. 35634). Oncor requested a nonbypassable charge to be billed to REPs serving customer classes that receive services under Oncor’s energy efficiency program. The proposed recovery factor is $0.22 per month for each residential customer and will vary for non-residential customers. The proposed charge will allow Oncor, in a timely manner, to recover reasonable and necessary costs incurred in administering its energy efficiency program. In October 2008, the PUCT approved the recovery factor. Oncor began billing the surcharge in the January 2009 billing month cycle.

Transmission Rates — In order to recover increases in its transmission costs, including fees paid to other transmission service providers, Oncor is allowed to request an update twice a year to the transmission cost recovery factor (TCRF) component of its retail delivery rate charged to REPs. In January 2009, an application was filed to increase the TCRF, which was administratively approved in February 2009 and became effective March 1, 2009. This increase is expected to increase annualized revenues by $16 million.

In February 2008, Oncor filed an application for an interim update of its wholesale transmission rate. The PUCT approved Oncor’s application in April 2008, and the new rate went into effect immediately. Annualized revenues are expected to increase by approximately $39 million. Approximately $25 million of this increase is recoverable through transmission rates charged to wholesale customers, and the remaining $14 million is recoverable from REPs through the TCRF component of Oncor’s delivery rates charged to REPs as discussed immediately above. With the pending rate case discussed above, Oncor has not filed for an interim update of it wholesale transmission rate in 2009.

Competitive Renewable Energy Zones (CREZ) — In the first quarter of 2007, the PUCT initiated a docket to identify the transmission facilities necessary to interconnect future renewable energy generating facilities. As part of the docket, the PUCT considered which zones would contain the best renewable energy sources. In July 2007, the PUCT voted to designate zones with generation potential of over 20,000 MW. In July 2008, the PUCT approved a plan for the construction of transmission facilities with an estimated cost of $4.9 billion to accommodate over 18,000 MW of wind capacity.

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In September 2008, parties interested in the construction and operation of CREZ transmission facilities filed CREZ Transmission Plans. Oncor and several other ERCOT utilities filed a joint CREZ Transmission Plan, which includes the joint parties’ plans to construct and operate all of the CREZ transmission facilities. Hearings on the CREZ Transmission Plan proposals were held in December 2008. At a January 2009 open meeting, the PUCT assigned approximately $1.3 billion of CREZ construction projects to Oncor. Oncor anticipates that a written order reflecting the PUCT’s decisions will be entered in the first quarter of 2009. The cost estimates for the CREZ construction projects are based upon cost analyses prepared by ERCOT. Oncor anticipates completing the necessary permitting actions and other requirements and all construction activities so that its CREZ Transmission Plan may be implemented consistent with the PUCT’s assignment. The PUCT’s assignment calls for construction to be completed in 2012.

Summary

EFH Corp. cannot predict future regulatory or legislative actions or any changes in economic and securities market conditions. Such actions or changes could significantly alter its basic financial position, results of operations or cash flows.

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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk that EFH Corp. may experience a loss in value as a result of changes in market conditions affecting factors such as commodity prices and interest rates, to which EFH Corp. is exposed in the ordinary course of business. EFH Corp.’s exposure to market risk is affected by a number of factors, including the size, duration and composition of its energy and financial portfolio, as well as the volatility and liquidity of markets. EFH Corp. enters into instruments such as interest rate swaps to manage interest rate risk related to its indebtedness, as well as exchange traded, over-the-counter contracts and other contractual commitments to manage commodity price risk as part of its wholesale activities. EFH Corp.’s interest rate risk discussed below was significantly affected by debt issuances in connection with the Merger.

Risk Oversight

TCEH manages 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 EFH Corp.’s 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 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 the various businesses of EFH Corp. and their associated transactions.

Commodity Price Risk

EFH Corp.’s businesses are subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products they market or purchase. EFH Corp.’s businesses actively manage their portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. These businesses, similar to other participants in the market, 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, subsidiaries of EFH Corp. 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 in the wholesale operations include hedging, the structuring of long-term contractual arrangements and proprietary trading. The wholesale operation continuously monitors the valuation of identified risks and adjusts positions based on current market conditions. EFH Corp. strives to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

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

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

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

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

	Successor
	Year Ended December 31, 2008		Year Ended December 31, 2007
Month-end average Trading VaR:	$	6	$	9
Month-end high Trading VaR:	$	15	$	14
Month-end low Trading VaR:	$	2	$	6

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.

	Successor
	Year Ended December 31, 2008		Year Ended December 31, 2007
Month-end average MtM VaR:	$	2,290	$	1,081
Month-end high MtM VaR:	$	3,549	$	1,576
Month-end low MtM VaR:	$	1,087	$	322

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.

	Successor
	Year Ended December 31, 2008		Year Ended December 31, 2007
Month-end average EaR:	$	2,300	$	1,070
Month-end high EaR:	$	3,916	$	1,559
Month-end low EaR:	$	1,069	$	318

The increases in the risk measures (MtM VaR and EaR) above were driven by higher natural gas prices and significant increases in market volatility.

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Interest Rate Risk

The table below provides information concerning EFH Corp.’s financial instruments as of December 31, 2008 and 2007 that are sensitive to changes in interest rates, which include debt obligations and interest rate swaps. EFH Corp. has entered into interest rate swaps under which it has agreed to exchange the difference between fixed-rate and variable-rate interest amounts calculated with reference to specified notional principal amounts at dates that generally coincide with interest payments. In addition, in connection with entering into certain interest rate basis swaps to further reduce fixed borrowing costs, EFH Corp. has changed the variable interest rate terms of certain debt from three-month LIBOR to one-month LIBOR, as discussed in Note 15 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 and fair value hedges are excluded from the table. See Note 15 to Financial Statements for a discussion of changes in debt obligations.

	Expected Maturity Date																		Successor
	(millions of dollars, except percentages)
	2009			2010			2011			2012			2013			There- After			2008 Total Carrying Amount			2008 Total Fair Value		2007 Total Carrying Amount			2007 Total Fair Value
Long-term debt (including current maturities)
Fixed rate debt amount (a)	$	198		$	135		$	559		$	851		$	866		$	18,037		$	20,646		$	14,266	$	19,614		$	18,987
Average interest rate		5.59	%		5.46	%		5.66	%		6.24	%		6.00	%		9.10	%		8.70	%				8.74	%
Variable rate debt amount	$	173		$	200		$	200		$	200		$	200		$	20,288		$	21,261		$	14,886	$	20,256		$	19,909
Average interest rate		5.44	%		5.40	%		5.40	%		5.40	%		5.40	%		5.28	%		5.28	%				8.29	%
Total debt	$	371		$	335		$	759		$	1,051		$	1,066		$	38,325		$	41,907		$	29,152	$	39,870		$	38,896
Debt swapped to variable: Amount	$	—		$	—		$	—		$	—		$	—		$	—		$	—				$	200
Average pay rate		—			—			—			—			—			—			—					7.48	%
Average receive rate		—			—			—			—			—			—			—					6.38	%
Debt swapped to fixed: Amount	$	1,250		$	500		$	600		$	2,600		$	3,600		$	9,000		$	17,550				$	15,050
Average pay rate		7.33	%		7.43	%		7.57	%		7.99	%		7.60	%		8.31	%		8.00	%				8.01	%
Average receive rate		5.89	%		5.89	%		5.89	%		5.89	%		5.83	%		5.89	%		5.88	%				8.40	%
Variable basis swaps: Amount	$	6,345		$	1,100		$	1,500		$	4,100		$	—		$	—		$	13,045					—
Average pay rate		2.51	%		2.39	%		2.67	%		2.39	%		—			—			2.48	%				—
Average receive rate		2.07	%		1.82	%		2.32	%		1.82	%		—			—			2.00	%				—

(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 15 to Financial Statements for details concerning long-term debt subject to mandatory tender for remarketing.

As of December 31, 2008, the potential reduction of annual pretax earnings due to a one-point increase in interest rates totaled approximately $26 million, taking into account the interest rate swaps discussed in Note 15 to the Financial Statements.

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Credit Risk

Credit Risk— Credit risk relates to the risk of loss associated with nonperformance by counterparties. EFH Corp. and its subsidiaries maintain credit risk policies with regard to their 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 specify authorized 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. EFH Corp. has processes for monitoring and managing credit exposure of its 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, EFH Corp. has established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material adverse 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 — EFH Corp.’s gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions arising from hedging and trading activities totaled $2.270 billion at December 31, 2008. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of December 31, 2008 include $715 million in accounts receivable from the retail sale of electricity to residential and business customers. As of December 31, 2008, EFH Corp. held cash deposits of $108 million as collateral for these receivables. 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.

Most of the remaining credit exposure is with wholesale counterparties. These counterparties 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, 2008, the exposure to credit risk from the wholesale customers and counterparties totaled $1.331 billion taking into account standardized master netting contracts and agreements described above but before taking into account $536 million in credit collateral (cash, letters of credit and other security interests) held by EFH Corp. subsidiaries.

Of this $795 million net exposure, 82% is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and EFH Corp.’s 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. EFH Corp. routinely monitors and manages its credit exposure to these customers and counterparties on this basis. See discussion above under “Bankruptcy Filing of Lehman Brothers Holdings Inc.”

In addition, Oncor has exposure to credit risk from nonaffiliated parties totaling $224 million at December 31, 2008, of which $194 million represents trade accounts receivable principally from REPs. This exposure consists almost entirely of noninvestment grade trade accounts receivable. Oncor has one customer that represents 12% of the total exposure to nonaffiliated parties.

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The following table presents the distribution of credit exposure as of December 31, 2008, for wholesale counterparties. 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 within each contract and any master netting contracts with counterparties. The amounts below do not include asset liens held as security for a portion of the net exposure.

	Exposure Before Credit Collateral			Credit Collateral		Net Exposure			Net Exposure by Maturity
									2 years or less		Between 2-5 years		Greater than 5 years		Total
Investment grade	$	1,180		$	528	$	652		$	503	$	83	$	66	$	652
Noninvestment grade		151			8		143			140		3		—		143
Totals	$	1,331		$	536	$	795		$	643	$	86	$	66	$	795
Investment grade		89	%				82	%
Noninvestment grade		11	%				18	%

In addition to the exposures in the table above, EFH Corp. has contracts classified as “normal” purchase or sale and non-derivative contractual commitments that 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 adverse impact on EFH Corp.’s future results of operations, financial condition and cash flows.

EFH Corp. does not anticipate any material adverse effect on its financial position or results of operations due to nonperformance by any customer or counterparty.

EFH Corp.’s subsidiaries had credit exposure to two counterparties each having an exposure greater than 10% of the net $795 million credit exposure. These two counterparties represented 29% and 18%, respectively, of the net exposure. EFH Corp. views exposure to these counterparties to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and business relationship with EFH Corp. However, this concentration increases the risk that a default would have a material effect on EFH Corp.’s net income and cash flows.

With respect to credit risk related to the long-term hedging program, over 98% of the transaction volumes are with counterparties with an A credit rating or better. However, EFH Corp. has 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 of EFH Corp.’s hedge counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if EFH Corp. owes amounts related to its commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to EFH Corp. While EFH Corp. views the potential concentration of risk with these counterparties to be within an acceptable risk tolerance, EFH Corp. strives to manage its exposure to its hedge counterparties through various ongoing risk management measures.

112

FORWARD-LOOKING STATEMENTS

This report and other presentations made by EFH Corp. 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 EFH Corp. expects or anticipates 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 EFH Corp.’s business and operations (often, but not always, through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “projection,” “target,” and “outlook”), are forward-looking statements. Although EFH Corp. believes that in making any such forward-looking statement its 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 “Risk Factors” and the following important factors, among others, that could cause the actual results of EFH Corp. 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, FERC, the PUCT, the RRC, the NRC, the EPA and the TCEQ, with respect to, among other things:

• allowed prices;

• allowed rates of return;

• industry, market and rate structure;

• purchased power and recovery of investments;

• operations of nuclear generating facilities;

• operations of mines;

• acquisitions 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, and

• changes in and compliance with environmental and safety laws and policies, including climate change initiatives;

• legal and administrative proceedings and settlements;

• general industry trends;

• EFH Corp.’s ability to attract and retain profitable customers;

• EFH Corp.’s ability to profitably serve its customers;

• restrictions on competitive retail pricing;

• changes in wholesale electricity prices or energy commodity prices;

• 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;

• EFH Corp.’s ability to effectively hedge against changes in commodity prices, market heat rates and interest rates;

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

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

• 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;

• competition for new energy development and other business opportunities;

• inability of various counterparties to meet their obligations with respect to EFH Corp.’s financial instruments;

• changes in technology used by and services offered by EFH Corp.;

• significant changes in EFH Corp.’s relationship with its 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 pension and OPEB benefits, and future funding requirements related thereto;

113

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

• significant changes in critical accounting policies;

• actions by credit rating agencies;

• economic conditions;

• the ability of EFH Corp. to implement cost reduction initiatives, and

• with respect to EFH Corp.’s lignite coal-fueled generation construction and development program, more specifically, EFH Corp.’s ability to fund such investments, changes in competitive market rules, unexpected judicial rulings, changes in environmental laws or regulations, changes in electric generation and emissions control technologies, changes in projected demand for electricity, the ability of EFH Corp. and its contractors to attract and retain, at projected rates, skilled labor for constructing the new generating units, changes in wholesale electricity prices or energy commodity prices, transmission capacity and constraints, supplier performance risk, changes in the cost and availability of materials necessary for the construction program and the ability of EFH Corp. to manage the significant construction, commissioning and start-up program to a timely conclusion with limited cost overruns.

Any forward-looking statement speaks only as of the date on which it is made, and EFH Corp. undertakes 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 EFH Corp. to predict all of them; nor can EFH Corp. 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.

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. EFH Corp. did not commission any of these publications or reports. Some data is also based on EFH Corp.’s good faith estimates, which are derived from EFH Corp.’s 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 it believes that each of these studies and publications is reliable, EFH Corp. has not independently verified such data and makes no representation as to the accuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and EFH Corp. does not know what assumptions regarding general economic growth are used in preparing the forecasts included in this report. Similarly, while EFH Corp. believes that its internal and external research is reliable, it has not been verified by any independent sources, and EFH Corp. makes no assurances that the predictions contained therein are accurate.

114

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) as of December 31, 2008 and 2007 (successor), and the related statements of consolidated income (loss), comprehensive income (loss), cash flows and shareholders’ equity for the year ended December 31, 2008 (successor), the period from October 11, 2007 through December 31, 2007 (successor), the period from January 1, 2007 through October 10, 2007 (predecessor) and the year ended December 31, 2006 (predecessor). These financial statements are the responsibility of EFH Corp.’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 Holdings Corp. and subsidiaries at December 31, 2008 and 2007 (successor), and the results of their operations and their cash flows for the year ended December 31, 2008 (successor), the period from October 11, 2007 through December 31, 2007 (successor), the period from January 1, 2007 through October 10, 2007 (predecessor) and the year ended December 31, 2006 (predecessor), in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, EFH Corp. completed its merger with Texas Energy Future Merger Sub Corp and became a subsidiary of Texas Energy Future Holdings Limited Partnership on October 10, 2007. As also discussed in Note 1 to the consolidated financial statements, EFH Corp. adopted the provisions of FASB Staff Position No. FIN 39-1 and reclassified the results of its commodity hedging and trading activities on a retrospective basis.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on the criteria established inInternal Control – Integrated Framework issued by the Committee Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2009 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Dallas, Texas

March 2, 2009

115

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Millions of Dollars)

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Operating revenues	$	11,364		$	1,994		$	8,044		$	10,703
Fuel, purchased power costs and delivery fees		(4,595	)		(644	)		(2,381	)		(2,784	)
Net gain (loss) from commodity hedging and trading activities		2,184			(1,492	)		(554	)		153
Operating costs		(1,503	)		(306	)		(1,107	)		(1,373	)
Depreciation and amortization		(1,610	)		(415	)		(634	)		(830	)
Selling, general and administrative expenses		(957	)		(216	)		(691	)		(819	)
Franchise and revenue-based taxes		(363	)		(93	)		(282	)		(390	)
Impairment of goodwill (Note 3)		(8,860	)		—			—			—
Other income (Note 13)		80			14			69			121
Other deductions (Note 13)		(1,301	)		(61	)		(841	)		(269	)
Interest income		27			24			56			46
Interest expense and related charges (Note 28)		(4,935	)		(839	)		(671	)		(830	)
Income (loss) from continuing operations before income taxes and minority interests		(10,469	)		(2,034	)		1,008			3,728
Income tax (expense) benefit		471			673			(309	)		(1,263	)
Minority interests in net loss of consolidated subsidiaries (Note 18)		160			—			—			—
Income (loss) from continuing operations		(9,838	)		(1,361	)		699			2,465
Income from discontinued operations, net of tax effect (Note 4)		—			1			24			87
Net income (loss)	$	(9,838	)	$	(1,360	)	$	723		$	2,552

See Notes to Financial Statements.

116

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Millions of Dollars)

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Net income (loss)	$	(9,838	)	$	(1,360	)	$	723		$	2,552
Other comprehensive income (loss), net of tax effects:
Reclassification of pension and other retirement benefit costs (net of tax (expense) benefit of $69, $5, $(19) and $—) (Note 22)		(84	)		(57	)		49			—
Minimum pension liability adjustments (net of tax (expense) benefit of $—, $—, $— and $(38))		—			—			—			71
Cash flow hedges:
Net increase (decrease) in fair value of derivatives (net of tax (expense) benefit of $99, $97, $154 and $(321))		(183	)		(177	)		(288	)		598
Derivative value net (gains) losses related to hedged transactions recognized during the period and reported in net income (net of tax (expense) benefit of $66, $— , $(48) and $(25))		122			—			(89	)		(45	)
Total effect of cash flow hedges		(61	)		(177	)		(377	)		553
Total adjustments to net income (loss)		(145	)		(234	)		(328	)		624
Comprehensive income (loss)	$	(9,983	)	$	(1,594	)	$	395		$	3,176

See Notes to Financial Statements.

117

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Cash flows — operating activities
Net income (loss)	$	(9,838	)	$	(1,360	)	$	723		$	2,552
Income from discontinued operations, net of tax effect		—			(1	)		(24	)		(87	)
Income (loss) from continuing operations		(9,838	)		(1,361	)		699			2,465
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Depreciation and amortization		2,070			568			684			893
Deferred income tax expense (benefit) – net		(477	)		(736	)		(111	)		756
Impairment of goodwill (Note 3)		8,860			—			—			—
Impairment of trade name intangible asset (Note 3)		481			—			—			—
Impairment of emission allowances intangible assets (Note 3)		501			—			—			—
Impairment of natural gas-fueled generation fleet (Note 6)		229			—			—			198
Charge related to Lehman bankruptcy (Note 13)		26			—			—			—
Unrealized net losses (gains) from mark-to-market valuations of commodity positions		(2,329	)		1,556			722			(272	)
Unrealized net losses from mark-to-market valuations of interest rate swaps		1,477			—			—			—
Bad debt expense		81			12			46			68
Stock-based incentive compensation expense		30			—			27			27
Recognition of losses on dedesignated cash flow hedges		66			—			10			12
Customer appreciation bonus charge (net of amounts credited to customers in 2006) (Note 7)		—			—			—			122
Net charges related to cancelled development of generation facilities (Note 5)		—			2			676			—
Write-off of deferred transaction costs (Note 13)		—			—			38			—
Credit related to impaired leases (Note 13)		—			—			(48	)		(2	)
Net gains on sale of assets, including amortization of deferred gains		(1	)		(1	)		(40	)		(69	)
Minority interests in net loss of consolidated subsidiaries		(160	)		—			—			—
Other, net		(20	)		5			19			16
Changes in operating assets and liabilities:
Accounts receivable – trade		(505	)		309			(200	)		337
Impact of accounts receivable sales program (Note 14)		53			(336	)		72			(44	)
Inventories		(21	)		(5	)		(7	)		(21	)
Accounts payable – trade		385			(264	)		81			(219	)
Commodity and other derivative contractual assets and liabilities		(28	)		18			(185	)		—
Margin deposits – net		595			(614	)		(569	)		564
Other – net assets		440			284			(89	)		(92	)
Other – net liabilities		(410	)		113			440			215
Cash provided by (used in) operating activities from continuing operations	$	1,505		$	(450	)	$	2,265		$	4,954

See Notes to Financial Statements.

118

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.)

(Millions of Dollars)

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Cash flows — financing activities
Issuances of securities/long-term borrowings (Note 15):
Equity financing from Sponsor Group and other investors	$	—		$	8,236		$	—		$	—
Merger-related debt financing		—			42,732			1,800			—
Pollution control revenue bonds		242			—			—			243
Oncor long-term debt		1,500
Other long-term debt		1,443			—			—			—
Common stock		34			—			1			180
Retirements/repurchases of securities/long-term borrowings (Note 15):
Equity-linked debt		—			—			—	��		(179	)
Pollution control revenue bonds		(242	)		—			(143	)		(259	)
Merger-related debt repurchases		—			(15,314	)		—			—
Other long-term debt		(925	)		(81	)		(302	)		(1,253	)
Common stock		(3	)		—			(13	)		(960	)
Increase (decrease) in short-term borrowings (Note 15):
Banks		(481	)		(722	)		2,245			(245	)
Commercial paper		—			—			(1,296	)		939
Common stock dividends paid		—			—			(788	)		(764	)
Settlements of minimum withholding tax liabilities under stock-based compensation plans		—			—			(93	)		(52	)
Excess tax benefit on stock-based incentive compensation		—			—			—			41
Debt discount, financing and reacquisition expenses		(21	)		(986	)		(17	)		(23	)
Other		37			—			—			—
Cash provided by (used in) financing activities from continuing operations		1,584			33,865			1,394			(2,332	)
Cash flows — investing activities
Acquisition of EFH Corp.		—			(32,694	)		—			—
Capital expenditures		(2,812	)		(684	)		(2,341	)		(2,180	)
Nuclear fuel purchases		(166	)		(23	)		(54	)		(117	)
Investment held in money market fund (Note 1)		(142	)		—			—			—
Proceeds from sale of minority interests, net of transaction costs (Note 18)		1,253			—			—			—
Purchase of mining-related assets		—			—			(122	)		—
Proceeds from sale of assets		80			86			71			20
Proceeds from sale of environmental allowances and credits		39			—			—			—
Purchases of environmental allowances and credits		(34	)		—			—			—
Purchase of lease trust		—			—			—			(69	)
Proceeds from letter of credit facility deposited with trustee (restricted cash) (Note 15)		—			(1,250	)		—			—
Proceeds from pollution control revenue bonds (deposited) withdrawn from trustee (restricted cash)		29			13			202			(240	)
Other changes in restricted cash		1			14			(16	)		—
Cash settlements related to outsourcing contract termination (Note 21)		70			—			—			—
Proceeds from sales of nuclear decommissioning trust fund securities		1,623			831			602			207
Investments in nuclear decommissioning trust fund securities		(1,639	)		(835	)		(614	)		(223	)
Costs to remove retired property		(37	)		(9	)		(25	)		(40	)
Settlement of loan (Note 21)		25			—			—			—
Other		29			(12	)		14			(22	)
Cash used in investing activities from continuing operations		(1,681	)		(34,563	)		(2,283	)		(2,664	)

119

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.)

(Millions of Dollars)

	Successor					Predecessor
	Year Ended December 31, 2008		Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007		Year Ended December 31, 2006
Discontinued operations:
Cash provided by (used in) operating activities		—		(7	)		35		30
Cash used in financing activities		—		—			—		—
Cash provided by (used in) investing activities		—		—			—		—
Cash provided by (used in) discontinued operations		—		(7	)		35		30
Net change in cash and cash equivalents		1,408		(1,155	)		1,411		(12	)
Cash and cash equivalents — beginning balance		281		1,436			25		37
Cash and cash equivalents — ending balance	$	1,689	$	281		$	1,436	$	25

See Notes to Financial Statements.

120

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

	Successor
	December 31, 2008			December 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	1,689		$	281
Investments held in money market fund (Note 1)		142			—
Restricted cash (Note 28)		55			56
Trade accounts receivable — net (Note 14)		1,219			1,099
Income taxes receivable — net		42			101
Inventories (Note 28)		426			405
Commodity and other derivative contractual assets (Note 19)		2,534			1,129
Accumulated deferred income taxes (Note 12)		44			9
Margin deposits related to commodity positions		439			513
Other current assets		165			376
Total current assets		6,755			3,969
Restricted cash (Note 28)		1,267			1,296
Investments (Note 20)		645			868
Property, plant and equipment — net (Note 28)		29,522			28,650
Goodwill (Note 3)		14,386			22,954
Intangible assets — net (Note 3)		2,993			4,365
Regulatory assets — net (Note 28)		1,892			1,305
Commodity and other derivative contractual assets (Note 19)		962			244
Other noncurrent assets, principally unamortized debt issuance costs		841			1,130
Assets held for sale		—			23
Total assets	$	59,263		$	64,804
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings (Note 15)	$	1,237		$	1,718
Long-term debt due currently (Note 15)		385			513
Trade accounts payable		1,143			904
Commodity and other derivative contractual liabilities (Note 19)		2,908			1,146
Margin deposits related to commodity positions		525			5
Accrued interest		524			537
Other current liabilities		612			879
Total current liabilities		7,334			5,702
Accumulated deferred income taxes (Note 12)		5,926			6,664
Investment tax credits		42			47
Commodity and other derivative contractual liabilities (Note 19)		2,095			2,453
Long-term debt, less amounts due currently (Note 15)		40,838			38,603
Other noncurrent liabilities and deferred credits (Note 28)		5,205			4,650
Total liabilities		61,440			58,119
Commitments and Contingencies (Note 16)
Minority interests (Note 18)		1,355			—
Shareholders’ equity (Note 17)		(3,532	)		6,685
Total liabilities and shareholders’ equity	$	59,263		$	64,804

See Notes to Financial Statements.

121

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED SHAREHOLDERS’ EQUITY

(Millions of Dollars)

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Common stock without par value (number of authorized shares — Successor — 2,000,000,000; Predecessor — 1,000,000,000):
Balance at beginning of period	$	—		$	—		$	5		$	5
Balance at end of period (number of shares outstanding: Successor: 2008 — 1,667,149,663; 2007 — 1,664,345,953; Predecessor: October 10, 2007 — 461,152,009; 2006 — 459,244,523)		—			—			5			5
Additional paid-in capital:
Balance at beginning of period		8,279			—			1,104			1,840
Investment by Sponsor Group and other investors		—			8,279			—			—
Effects of stock-based incentive compensation plans		29			—			(66	)		27
Effect of sale of minority interests (Note 18)		(265	)		—			—			—
Common stock repurchases		—			—			(13	)		(1,012	)
Excess tax benefit on stock-based compensation		—			—			82			41
Issuance of shares under equity-linked debt securities		—			—			—			180
Cost of Thrift Plan shares released by LESOP trustee (Note 22)		—			—			210			2
Effects of executive deferred compensation plan		—			—			11			13
Other		2			—			(2	)		13
Balance at end of period		8,045			8,279			1,326			1,104
Retained earnings (deficit):
Balance at beginning of period		(1,360	)		—			622			(1,168	)
Net income (loss)		(9,838	)		(1,360	)		723			2,552
Dividends declared on common stock ($—, $—, $1.30 and $1.67 per share)		—			—			(596	)		(768	)
Effect of adoption of FIN 48 (Note 10)		—			—			33			—
LESOP dividend deduction tax benefit and other		—			—			3			6
Balance at end of period		(11,198	)		(1,360	)		785			622
Accumulated other comprehensive gain (loss), net of tax effects:
Pension and other postretirement employee benefit liability adjustments:
Balance at beginning of period		(57	)		—			(2	)		(60	)
Change in unrecognized gains (losses) related to pension and other retirement benefit costs		(84	)		(57	)		49			—
Change in minimum pension liability		—			—			—			71
SFAS 158 transition adjustment		—			—			—			(13	)
Balance at end of period		(141	)		(57	)		47			(2	)
Amounts related to cash flow hedges:
Balance at beginning of period		(177	)		—			411			(142	)
Change during the period		(61	)		(177	)		(377	)		553
Balance at end of period		(238	)		(177	)		34			411
Total accumulated other comprehensive gain (loss) at end of period		(379	)		(234	)		81			409
Shareholders’ equity at end of period	$	(3,532	)	$	6,685		$	2,197		$	2,140

See Notes to Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

EFH Corp., a Texas corporation, is a Dallas-based holding company conducting its operations principally through its TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is engaged in regulated electricity transmission and distribution operations in Texas.

On October 10, 2007, EFH Corp. completed its Merger with Merger Sub. As a result of the Merger, EFH Corp. became a subsidiary of Texas Holdings, which is controlled by the Sponsor Group.

Various “ring-fencing” measures have been taken, in connection with the Merger, to enhance the credit quality of Oncor. Such measures include, among other things: the formation of a new special purpose holding company for Oncor, Oncor Holdings, as one of the Oncor Ring-Fenced Entities; the conversion of Oncor from a corporation to a limited liability company; maintenance of separate books and records for the Oncor Ring-Fenced Entities; changes to Oncor’s corporate governance provisions; appointment of a majority of independent directors to Oncor’s board of directors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or other obligations of any member of the Texas Holdings Group. Moreover, the cash flows of the Oncor Ring-Fenced Entities and their results of operations are separate from those of the Texas Holdings Group. Oncor Holdings is consolidated with EFH Corp. as a variable interest entity under FIN 46R.

See Note 18 for discussion of minority interests sold by Oncor in November 2008.

EFH Corp. has two reportable segments: the Competitive Electric segment, which includes the activities of TCEH as well as equipment salvage and resale activities related to the 2007 cancelled development of new generation facilities, and the Regulated Delivery segment, which includes the activities of Oncor, its wholly-owned bankruptcy-remote financing subsidiary and, in 2007, certain revenues and costs associated with installation of equipment that will facilitate Oncor’s technology initiatives. See Note 27 for further information concerning reportable business segments.

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Basis of Presentation

The consolidated financial statements of EFH Corp. have been prepared in accordance with US GAAP. The accompanying consolidated statements of income (loss), comprehensive income (loss) and cash flows present results of operations and cash flows of EFH Corp. for “Successor” and “Predecessor” periods, which relate to periods succeeding and preceding the Merger, respectively. The consolidated financial statements have been prepared on the same basis as the audited financial statements included in EFH Corp.’s 2007 Form 10-K, with the exception of a change to discontinue the netting of derivative assets and liabilities under master netting agreements as allowed under FSP FIN 39-1, a change in classification to report the results of commodity hedging and trading activities on a separate line item in the income statement instead of within operating revenues, as discussed immediately below, and certain reclassifications in the statements of consolidated comprehensive income (loss) to conform to current period presentation. The consolidated financial statements of the Successor reflect the application of purchase accounting in accordance with the provisions of SFAS 141, include the activities of Merger Sub, all of which related to the acquisition of EFH Corp., and reflect the adoption of SFAS 157. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

Change in Classification of Results from Commodity Hedging and Trading Activities— Effective April 1, 2008, EFH Corp. changed its classification of realized and unrealized net gains and losses from commodity hedging and trading activities such that the results from these activities are reported as a separate line on the income statement. Prior to April 1, 2008, such amounts were included within operating revenues. EFH Corp. believes this change in classification provides users of the financial statements better transparency of underlying revenue trends. Results from commodity hedging and trading activities are volatile as a substantial majority of the activity involves natural gas financial instruments, which are used to economically hedge future cash flows from electricity sales and are marked-to-market in net income. Comparative financial statements of prior periods reflect this reclassification. The following table presents EFH Corp.’s operating revenues as reported in the 2007 Form 10-K and reflects the change in classification. There is no effect on reported earnings, the balance sheet or the statement of cash flows as a result of this change in presentation.

	Successor						Predecessor
	As Originally Reported			As Reclassified			As Originally Reported		As Reclassified			As Originally Reported		As Reclassified
	Period from October 11, 2007 through December 31, 2007			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007		Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006		Year Ended December 31, 2006
Operating revenues	$	502		$	1,994		$	7,490	$	8,044		$	10,856	$	10,703
Net gain (loss) from commodity hedging and trading activities		n/a			(1,492	)		n/a		(554	)		n/a		153
Income (loss) from continuing operations		(1,361	)		(1,361	)		699		699			2,465		2,465

Discontinued Businesses

Note 4 presents detailed information regarding the effects of discontinued businesses, the results of which have been classified as discontinued operations.

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Use of Estimates

Preparation of EFH Corp.’s 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 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. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates or assumptions during the current year.

Purchase Accounting

The Merger has been accounted for under purchase accounting, whereby the total purchase price of the transaction was allocated to EFH Corp.’s identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values, and the excess of the purchase price over the fair value of net assets acquired was recorded as goodwill. The allocation resulted in a significant amount of goodwill, an increase in the carrying value of property, plant and equipment and deferred income tax liabilities as well as new identifiable intangible assets and liabilities. Reported earnings in periods subsequent to the Merger reflect increases in interest, depreciation and amortization expense. See Note 2 for details regarding the effect of purchase accounting.

Derivative Instruments and Mark-to-Market Accounting

EFH Corp. enters into contracts for the purchase and sale of electricity, natural gas and other commodities and also enters into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. If the instrument meets the definition of a derivative under SFAS 133, 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 EFH Corp.’s unsettled derivative instruments under mark-to-market accounting are reported in the balance sheet as commodity and other derivative contractual assets or liabilities. 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 Note 19 and 24 for additional information regarding commodity and other derivative contractual assets and liabilities and fair value measurement. Under the election criteria of SFAS 133, EFH Corp. 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, SFAS 133 allows the designation of such instruments as cash flow or fair value hedges provided 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 or loss 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 recognized as the previously hedged transaction impacts earnings. 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.

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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. See Notes 15 and 19 for additional information concerning hedging activity.

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, realized gains and losses associated with physically settled sales and purchase derivative instruments are reported in revenues and fuel, purchased power costs and delivery fees.

Revenue Recognition

EFH Corp. records revenue from electricity sales and delivery service under the accrual method of accounting. Revenues are recognized when electricity or delivery services are provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the revenues earned from the meter reading date to the end of the period (unbilled revenue).

EFH Corp.’s reported revenues include, on a net basis, ERCOT electricity balancing transactions, which represent wholesale purchases and sales of electricity for real-time balancing purposes as measured in 15-minute intervals. As is industry practice, these purchases and sales with ERCOT, as the balancing energy clearinghouse agent, are reported net in the income statement. Although difficult to predict, it is expected that the balancing activity will frequently result in net revenues due in part to generation volumes exceeding retail load. EFH Corp. believes that presentation of this activity as a component of revenues more appropriately reflects EFH Corp.’s market position.

Impairment of Long-Lived Assets

EFH Corp. evaluates long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist in accordance with the requirements of SFAS 144. 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 6 for details of the impairment of the natural gas-fueled generation fleet recorded in 2008 and 2006.

Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 3 to Financial Statements for additional information.

Goodwill and Intangible Assets with Indefinite Lives

EFH Corp. evaluates goodwill and intangible assets with indefinite lives for impairment at least annually (as of October 1) in accordance with SFAS 142, “Goodwill and Other Intangible Assets.” The impairment tests performed are based on discounted cash flow analyses. See Note 3 for details of goodwill and intangible assets with indefinite lives, including discussion of goodwill and trade name intangible assets impairments recorded in 2008.

Amortization of Nuclear Fuel

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

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Major Maintenance

Major maintenance costs incurred during generation plant outages and the costs of other maintenance activities are charged to expense as incurred. This accounting is consistent with FASB Staff Position AUG AIR-1, “Accounting for Planned Major Maintenance Activities.”

Defined Benefit Pension Plans and Other Postretirement Employee Benefit Plans

EFH Corp. offers pension benefits based on either a traditional defined benefit formula or a cash balance formula and also offers certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from EFH Corp. Costs of pension and OPEB plans are determined in accordance with SFAS 87 and SFAS 106 and are dependent upon numerous factors, assumptions and estimates. Effective December 31, 2006, EFH Corp. adopted SFAS 158. See Note 22 for additional information regarding pension and OPEB plans.

Stock-Based Incentive Compensation

Prior to the Merger, EFH Corp. provided discretionary awards payable in its common stock to qualified managerial employees under its shareholder-approved long-term incentive plans. These awards were accounted for based on the provisions of SFAS 123R, which provides for the recognition of stock-based compensation expense over the vesting period based on the grant-date fair value of those awards. In December 2007, EFH Corp.’s board of directors established its 2007 Stock Incentive Plan, which 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 options and stock appreciation rights are being accounted for based upon the provisions of SFAS 123R. See Note 23 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; 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.

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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 EFH Corp. 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 charged to customers by EFH Corp. are intended to recover the taxes, but EFH Corp. is not acting as an agent to collect the taxes from customers.

Income Taxes

EFH Corp. files a consolidated federal income tax return, and federal income taxes are allocated substantially as if the entities were stand-alone corporations. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities. Effective with the sale of minority interests in Oncor (see Note 18), Oncor became a partnership for US federal income tax purposes, and EFH Corp. provides deferred income taxes on the difference between the book and tax basis of its investment in Oncor. Previously earned investment tax credits were deferred and amortized as a reduction of income tax expense over the estimated lives of the related properties. In connection with purchase accounting, the remaining unamortized investment tax credit amount related to unregulated businesses of $300 million was eliminated. Investment tax credits related to Oncor’s regulated operations will continue to be amortized over the lives of the related properties. Certain provisions of SFAS 109 provide that regulated enterprises are permitted to recognize deferred taxes as regulatory tax assets or tax liabilities if it is probable that such amounts will be recovered from, or returned to, customers in future rates.

Prior to 2007, EFH Corp. generally accounted for uncertainty related to positions taken on tax returns based on the probable liability approach consistent with SFAS 5. Effective January 1, 2007, the company adopted FIN 48 as discussed in Note 10.

Accounting for Contingencies

The financial results of EFH Corp. 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 16 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.

EFH Corp. held an interest in The Reserve’s US Government Fund, which began liquidation proceedings in September 2008 due to the credit crisis and withdrawal demands. In September 2008, EFH Corp. attempted to redeem its interest, totaling $242 million, in the US Government Fund, but due to the liquidation process, the funds were not immediately made available; accordingly, such amount was reclassified from cash and cash equivalents to investment held in money market fund. EFH Corp. received $100 million of the funds in November 2008 and the remaining $142 million in January 2009.

Restricted Cash

The terms of certain agreements require the restriction of cash for specific purposes. At December 31, 2008, $1.250 billion of cash is restricted to support letters of credit. See Note 15 and 28 for more details regarding this and other restricted cash.

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Property, Plant and Equipment

As a result of purchase accounting, carrying amounts of property, plant and equipment related to unregulated businesses at October 10, 2007 were adjusted to estimated fair values. Subsequent additions are recorded at cost. Regulated properties at Oncor continue to be reported at original cost, which is considered to be fair value due to the cost-based regulated returns associated with those assets. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead, including payroll-related costs.

Depreciation of EFH Corp’s property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties. As is common in the industry, the Predecessor historically recorded depreciation expense using composite depreciation rates that reflect blended estimates of the lives of major asset components as compared to depreciation expense calculated on an asset-by-asset basis. Effective with the Merger, depreciation expense for unregulated properties is calculated on an asset-by-asset basis. Estimated depreciable lives are based on management’s estimates of the assets’ economic useful lives.

Capitalized Interest and Allowance for Funds Used During Construction (AFUDC)

Interest related to qualifying construction projects and qualifying software projects are capitalized in accordance with SFAS 34. Oncor capitalizes AFUDC as a cost component of projects involving construction periods lasting greater than thirty days. AFUDC is a regulatory cost accounting procedure whereby both interest charges on borrowed funds and a return on equity capital used to finance construction are included in the recorded cost of utility plant and equipment being constructed. The equity portion of capitalized AFUDC is accounted for as other income; there was no equity AFUDC for the years presented. See Note 28.

Inventories

All 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. In connection with purchase accounting, inventory amounts at October 10, 2007 were recorded at fair value. Also see discussion immediately below regarding environmental allowances and credits.

Environmental Allowances and Credits

Effective with the Merger, EFH Corp. began accounting 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. In accordance with SFAS 144, the environmental allowances and credits are assessed for impairment when conditions or events occur that could affect the carrying value of the assets. See Note 3 for details of impairment amounts recorded in 2008. EFH Corp. previously accounted for environmental allowances and credits as inventory. Both accounting methods are acceptable under GAAP.

Regulatory Assets and Liabilities

The financial statements of EFH Corp.’s regulated electricity delivery operations reflect regulatory assets and liabilities under cost-based rate regulation in accordance with SFAS 71. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 28 for details of the regulatory assets and liabilities.

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Investments

Investments in a nuclear decommissioning trust fund are carried at market value in the balance sheet. Investments in unconsolidated business entities over which EFH Corp. has significant influence but does not maintain effective control, generally representing ownership of at least 20% and not more than 50% of common equity, are accounted for under the equity method. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at market value. See Note 20 for details of investments.

Sale of Minority Interests

See Note 18 for discussion of accounting for the sale of minority interests by Oncor.

Changes in Accounting Standards

In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.” SFAS 160 is effective for fiscal years beginning on or after December 15, 2008 and will require noncontrolling interests (now called minority interests) in subsidiaries initially to be measured at fair value and classified as a separate component of equity. Provisions are to be applied prospectively. Early adoption is prohibited. EFH Corp. will classify the minority interests created as a result of Oncor’s November 2008 sale of equity interests (see Note 18) as a separate component of equity in its balance sheet and consolidated net income (loss) shall be adjusted to include the net income attributable to the minority interests effective January 1, 2009 on a retrospective basis.

Effective January 1, 2008, EFH Corp. adopted FSP FIN 39-1, “Amendment of FASB Interpretation No. 39.” This FSP provides additional guidance regarding the offsetting in the balance sheet of cash collateral and derivative fair value asset and liability amounts. As provided for by this rule, for balance sheet presentation, EFH Corp. elected to not adopt netting of cash collateral, and further to discontinue netting of derivative assets and liabilities under master netting agreements. Accordingly, as required by the rule, prior period amounts in the financial statements reflect the change in presentation, resulting in an increase of $849 million and $171 million in both commodity and other derivative contractual current and noncurrent assets and liabilities, respectively, at December 31, 2007 compared to amounts reported in the 2007 Form 10-K.

In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement 133.” SFAS 161 enhances required disclosures regarding derivatives and hedging activities to enable investors to better understand their effects on an entity’s financial position, financial performance and cash flows. This statement is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. As SFAS 161 provides only disclosure requirements, the adoption of this standard will not have any effect on EFH Corp.’s reported results of operations or financial condition. EFH Corp. will provide the enhanced disclosures in its Form 10-Q for the three months ended March 31, 2009.

In October 2008, the FASB issued FSP SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active.” The FSP clarifies the application of SFAS 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. The FSP does not change the fair value measurement principles in SFAS 157. The FSP was effective upon issuance, including prior periods for which financial statements had not been issued. EFH Corp. has determined this FSP does not change its approach for measuring fair value of financial assets.

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Effective December 31, 2008, EFH Corp. adopted FSP SFAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities.” This FSP amends SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” to require additional disclosures about transfers of financial assets. It also amends FIN 46R, “Consolidation of Variable Interest Entities,” to require additional disclosures about an entity’s involvement with variable interest entities. The disclosures required by this FSP are intended to provide greater transparency about a transferor’s continuing involvement with transferred financial assets and an entity’s involvement with variable interest entities and qualifying special purpose entities (SPEs). As the FSP provides only disclosure requirements, the adoption of this FSP did not have any effect on EFH Corp.’s reported results of operations, financial condition or cash flows. See Note 14 for related disclosures.

In December 2008, the FASB issued FSP SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP amends SFAS 132(R) to provide enhanced disclosures regarding how investment allocation decisions are made and certain aspects of fair value measurements on plan assets. The disclosures required by this FSP are intended to provide transparency related to the types of assets and associated risks in an employer’s defined benefit pension or other postretirement employee benefits plan and events in the economy and markets that could have a significant effect on the value of plan assets. This FSP is effective for fiscal years ending after December 15, 2009. As the FSP provides only disclosure requirements, the adoption of this FSP will not have any effect on EFH Corp.’s reported results of operations, financial condition or cash flows. EFH Corp. is evaluating the impact of this FSP on its financial statement disclosures.

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2. FINANCIAL STATEMENT EFFECTS OF THE MERGER

As discussed in Note 1, the Merger was completed on October 10, 2007. The aggregate purchase price paid for the equity securities of EFH Corp. was $31.9 billion, which was financed by a combination of equity invested by the Sponsor Group and certain other investors and by borrowings under a senior secured credit facility and senior unsecured interim facilities. These facilities also funded the repayment and redemption of certain existing credit facilities and debt upon completion of the Merger. See Note 15 for a discussion of EFH Corp.’s debt.

The statements of consolidated income (loss) and cash flows for 2007 present Predecessor results from January 1 through October 10 and Successor results from October 11 through December 31.

Sources and Uses

The sources and uses of the funds for the Merger are summarized in the table below.

Sources of funds:			Uses of funds:
(billions of dollars)
Cash and other sources	$	0.3	Equity purchase price (b)	$	31.9
TCEH credit facilities (Note 15)		27.0	Transaction costs (c)		0.8
EFH Corp. senior unsecured interim facility (Note 15)		4.5	Repayment of existing debt (Note 15)		5.3
Equity contributions (a)		8.3	Restricted cash		1.2
			Financing fees related to new facilities		0.9
Total source of funds	$	40.1	Total uses of funds	$	40.1

(a) Consists of equity contributions by the Sponsor Group and certain other investors.

(b) Represents 461.2 million outstanding shares of EFH Corp. common stock multiplied by $69.25 per share.

(c) Represents professional fees incurred by the Sponsor Group that were directly associated with the Merger and accounted for as part of the purchase price.

Purchase Price Allocation

EFH Corp. accounted for the Merger under purchase accounting in accordance with the provisions of SFAS 141, whereby the total purchase price of the transaction was allocated to EFH Corp.’s identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of October 10, 2007 as summarized in the table below. The fair values were determined based upon assumptions related to future cash flows, discount rates, and asset lives as well as factors more unique to EFH Corp., its industry and the competitive wholesale power market that include forward natural gas price curves and market heat rates, retail customer attrition rates, generation plant operating and construction costs, and the effect on generation facility values of lignite fuel reserves and mining capabilities using currently available information. As a result of cost-based regulatory rate-setting processes, the book value of the majority of Oncor’s assets and liabilities effectively represent fair value, and no adjustments to those regulated assets or liabilities were recorded. The excess of the purchase price over the fair value of net assets acquired was recorded as goodwill.

The goodwill amount recorded upon finalization of purchase accounting in 2008 totaled $23.2 billion. Management believes the drivers of the goodwill amount include the incremental value of the future cash flow potential of the baseload generation facilities, including facilities under construction, over the values assigned to those assets under purchase accounting rules, considering the market-pricing mechanisms and growth potential in the ERCOT market, as well as the value derived from the scale of the retail business. Management also believes that the goodwill reflects the value of the relatively stable, long-lived cash flows of the regulated business, considering the constructive regulatory environment and market growth potential. See Note 3 for disclosures related to goodwill, including an impairment recorded in the fourth quarter of 2008.

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The following table summarizes the components of the final purchase price allocation:

Equity purchase price		$	31,935
Transaction costs			759
Total purchase price			32,694
Property, plant and equipment	28,088
Intangible assets (Note 3)	4,454
Regulatory assets and deferred debits	1,445
Other assets	5,187
Total assets acquired	39,174
Short-term borrowings and long-term debt	14,183
Deferred tax liabilities	7,706
Other liabilities	7,837
Total liabilities assumed	29,726
Net identifiable assets acquired			9,448
Goodwill		$	23,246

The following table summarizes the change in the total amount of goodwill during 2008 as a result of purchase accounting:

Goodwill at December 31, 2007			$	22,954
Property, plant and equipment	311
Intangible assets	30
Regulatory assets – net	2
Other assets	174
Total assets acquired	517
Deferred income tax liabilities	(263	)
Other liabilities	38
Total liabilities assumed	(225	)
Net identifiable assets acquired.				292
Goodwill at completion of purchase accounting			$	23,246

The above changes relate largely to finalization of fair values of natural gas-fueled generation plants and amounts related to the Capgemini outsourcing agreement, as well as the effects on related deferred income tax balances.

Exit liabilities originally recorded as part of the purchase price allocation totaled approximately $60 million, which consisted primarily of estimated amounts related to the cancellation of the development of coal-fueled generation facilities discussed in Note 5 and the exit of certain administrative activities. Such cancellation liabilities have been negotiated to a lesser amount and taking into consideration payments made, the exit liabilities have all been extinguished as of December 31, 2008. During 2008, additional exit liabilities totaling $66 million were recorded largely in connection with the termination of outsourcing arrangements with Capgemini under change of control provisions of such arrangements (also see Note 21). This amount is expected to be settled no later than June 30, 2011, the targeted date of completion of transition of outsourced activities back to EFH Corp. or to service providers.

Unaudited Pro Forma Financial Information

The following unaudited pro forma financial position and results of operations assume that the Merger-related transactions occurred on January 1, 2007 and 2006, respectively. The unaudited pro forma information is provided for informational purposes only and is not necessarily indicative of what EFH Corp.’s results of operations would have been if the Merger-related transactions had occurred on that date, or what EFH Corp.’s results of operations will be for any future periods.

For the year ended December 31, 2007, unaudited pro forma revenues and net loss were $10.0 billion and $2.3 billion, respectively. Pro forma adjustments for the year ended December 31, 2007 consist of adjustments for the Predecessor period and consist of $473 million in depreciation and amortization expense (including amounts recognized in revenues or fuel and purchased power costs), $2.1 billion in interest expense and a $895 million income tax benefit.

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For the year ended December 31, 2006, unaudited pro forma revenues and net income were $10.7 billion and $378 million, respectively. Pro forma adjustments for the year ended December 31, 2006 consist of adjustments for the Predecessor period and consist of $606 million in depreciation and amortization expense (including amounts recognized in revenues or fuel and purchased power costs), $2.8 billion in interest expense and a $1.2 billion income tax benefit.

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3. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

Reported goodwill as of December 31, 2008 totaled $14.4 billion, with $10.3 billion assigned to the Competitive Electric segment and $4.1 billion to the Regulated Delivery segment. As of December 31, 2007, reported goodwill totaled $23.0 billion with $18.1 billion assigned to the Competitive Electric segment and $4.9 billion to the Regulated Delivery segment. None of this goodwill balance is being deducted for tax purposes.

As discussed in Note 2, EFH Corp. accounted for the Merger under purchase accounting. The total goodwill amount recorded as a result of purchase accounting totaled $23.2 billion, representing the excess of the purchase price over the fair value of the tangible and identifiable intangible net assets acquired in the Merger; subsequently, an impairment charge was recorded in the fourth quarter of 2008 (discussed immediately below). SFAS 142 requires that goodwill be assigned to “reporting units”, which management has determined to be the Competitive Electric segment and the Regulated Delivery segment, which are largely comprised of TCEH and Oncor, respectively. The goodwill amounts assigned to the Competitive Electric segment of $18.3 billion and the Regulated Delivery segment of $4.9 billion were based on the enterprise values of those businesses at the closing date of the Merger and the completion of purchase accounting.

Goodwill and Trade Name Intangible Asset Impairments

In the fourth quarter of 2008, EFH Corp. recorded a goodwill impairment charge totaling $8.9 billion, which is not deductible for income tax purposes. This amount represents EFH Corp.’s best estimate of impairment pending finalization of the fair value calculations, which is expected in the first quarter of 2009. The total charge consists of an impairment of $8.0 billion related to the Competitive Electric segment and $860 million related to the Regulated Delivery segment. The impairment primarily arises from the dislocation in the capital markets that has increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of recent declines in market values of debt and equity securities of comparable companies.

Also in the fourth quarter of 2008, EFH Corp. recorded a trade name intangible asset impairment charge totaling $481 million ($310 million after-tax). The impairment primarily arises from the increase in the discount rate used in estimating fair value.

Although the annual goodwill and intangible assets with indefinite lives impairment test date set by management is October 1, management determined that in consideration of the continuing deterioration of securities values during the fourth quarter of 2008, an impairment testing trigger occurred subsequent to that test date; consequently, the impairment charges were based on estimated fair values at December 31, 2008.

The impairment determination involves significant assumptions and judgments in estimating enterprise values of the Competitive Electric and Regulated Delivery segments and the fair values of their assets and liabilities.

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Identifiable Intangible Assets

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

	Successor
	As of December 31, 2008						As of December 31, 2007
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	130	$	333	$	463	$	79	$	384
Favorable purchase and sales contracts		700		249		451		702		68		634
Capitalized in-service software		255		116		139		225		71		154
Environmental allowances and credits		994		121		873		1,525		19		1,506
Land easements and other		203		71		132		179		67		112
Total intangible assets subject to amortization	$	2,615	$	687		1,928	$	3,094	$	304		2,790
Trade name (not subject to amortization)						955						1,436
Mineral interests (not currently subject to amortization)						110						139
Total intangible assets					$	2,993					$	4,365

Amortization expense related to intangible assets consisted of:

	Successor					Predecessor
	Useful lives at December 31, 2008 (weighted average in years)	Year Ended December 31, 2008		Period from October 11, 2007 through December 31, 2007		Period from January 1, 2007 through October 10, 2007		Year Ended December 31, 2006
Retail customer relationship	4	$	51	$	79	$	—	$	—
Favorable purchase and sales contracts	10		168		72		—		—
Capitalized in-service software	8		44		8		23		35
Environmental allowances and credits	29		102		20		—		—
Land easements and other	69		4		—		2		2
Total amortization expense		$	369	$	179	$	25	$	37

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 pattern in which economic benefits are realized over their estimated useful life. Amortization expense related to the retail customer relationship intangible asset is reported as part of depreciation and amortization expense in the income statement (reported in the Competitive Electric segment).

• 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: 1) EFH Corp. has made the “normal” purchase or sale election allowed by SFAS 133 or 2) the contracts that did not meet the definition of a derivative. The amortization periods of these intangible assets are based on the terms of the contracts, and the expense is reported as part of revenues or fuel and purchased power costs in the income statement as appropriate (reported in the Competitive Electric segment). Unfavorable purchase and sales contracts are recorded as other noncurrent liabilities and deferred credits (see Note 28).

• 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 will be evaluated for impairment at least annually (as of October 1) in accordance with SFAS 142, “Goodwill and Other Intangible Assets.” See above for discussion of an impairment charge recorded in 2008.

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• Environmental Allowances and Credits –This intangible asset represents the fair value, based on observable prices or estimates, of environmental credits held by EFH Corp., substantially all of which were expected to be used in its power generation activity. These credits will be amortized to fuel and purchase power costs utilizing a units-of-production method (reported in the Competitive Electric segment).

Impairment of Environmental Allowances and Credits Intangible Assets

In March 2005, the EPA issued regulations called the Clean Air Interstate Rule (CAIR) for 28 states, including Texas, where EFH Corp.’s generation facilities are located. CAIR requires reductions of SO₂ and NOx emissions from power generation facilities in such states. The SO₂ reductions were beyond the reductions required under the Clean Air Act’s existing acid rain cap-and-trade program (the Acid Rain Program). CAIR also established a new regional cap-and-trade program for NOx emissions reductions.

In July 2008, the US Court of Appeals for the D.C. Circuit (the D.C. Circuit Court) invalidated CAIR. The D.C. Circuit Court did not overturn the existing cap-and-trade program for SO₂ reductions under the Acid Rain Program.

In the second quarter of 2008, EFH Corp. determined that certain of its SO₂ allowances had decreased materially in value, likely driven by litigation that resulted in the July 2008 decision from the D.C. Circuit Court invalidating CAIR. Accordingly, EFH Corp. recorded a $2 million (before deferred income tax benefit) impairment of certain SO₂ allowances.

Based on the D.C. Circuit Court’s ruling, EFH Corp. recorded a non-cash impairment charge to earnings in the third quarter of 2008. EFH Corp. impaired NOx allowances in the amount of $401 million (before deferred income tax benefit). As a result of the D.C. Circuit Court’s July 2008 decision, NOx allowances would no longer be needed, and thus there would not be an actively traded market for such allowances. Consequently, the NOx allowances held by EFH Corp. would likely have very little value absent reversal of the D.C. Circuit Court’s decision or promulgation of new rules by the EPA. In addition, EFH Corp. impaired SO₂ allowances in the amount of $98 million (before deferred income tax benefit). While the D.C. Circuit Court did not invalidate the Acid Rain Program, EFH Corp. would have more SO₂ allowances than it would need to comply with the Acid Rain Program. While there continued to be a market for SO₂ allowances, the D.C. Circuit Court’s decision resulted in a material decrease in the market price of SO₂ allowances.

The impairment amounts recorded in the second and third quarters of 2008 were reported in other deductions and are reflected in the results of the Competitive Electric segment.

In December 2008, in response to an EPA petition, the D.C. Circuit Court reversed, in part, its previous ruling. Such reversal confirmed CAIR is not valid, but allowed it to remain in place while the EPA revises CAIR to correct the previously identified shortcomings. Since the D.C. Circuit Court did not prescribe a deadline for this revision, at this time, EFH Corp. cannot predict how or when the EPA may revise CAIR.

Estimated Amortization of Intangible Assets–The estimated aggregate amortization expense of intangible assets for each of the five succeeding fiscal years from December 31, 2008 is as follows:

Year	Successor
2009	$	360
2010		225
2011		179
2012		137
2013		114

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4. DISCONTINUED OPERATIONS

Results from discontinued operations during the period October 11, 2007 to December 31, 2007 totaled $1 million in net income and during the period from January 1, 2007 to October 10, 2007 totaled $24 million in net income and consisted primarily of insurance proceeds related to the 2005 TXU Europe litigation settlement agreement in both periods.

Results from discontinued operations in 2006 totaled $87 million in net income. This amount included a $62 million credit representing reversal of a TXU Gas income tax reserve, due to favorable resolution of an IRS audit matter relating to a business sold in 2000, and a total of $27 million ($42 million pretax) in credits representing insurance recoveries associated with the TXU Europe settlement agreement.

5. CHARGES RELATED TO CANCELLED DEVELOPMENT OF COAL-FUELED GENERATION FACILITIES

In 2007, EFH Corp. recorded a net charge totaling $757 million ($492 million after-tax), substantially all of which was in the Predecessor period, in connection with the February 2007 suspension of the development of eight coal-fueled generation units. This decision and subsequent terminations of equipment orders required an evaluation of the recoverability of recorded assets associated with the development program. The net charge included $705 million for the impairment of construction work-in-process asset balances (primarily pre-construction development costs), $79 million for costs arising from terminations of equipment orders, $29 million for the write-off of deferred financing costs and a $57 million gain on sale (in early October 2007) of two in-process boilers. In determining the net charges recorded, EFH Corp. applied accounting rules for impairment of long-lived assets under SFAS 144 and for exit activities under SFAS 146. Additional charges totaling $12 million ($8 million after-tax) were recorded in 2008, which primarily represented costs for transportation and storage of materials.

The construction work-in-process asset balances totaled $871 million prior to the writedown and included progress payments made and accruals for amounts due to equipment suppliers, based on percentage of completion estimates, engineering and design services costs, site preparation expenditures, internal salary and related overhead costs for personnel engaged directly in construction management activities and capitalized interest. The construction work-in-process balance at December 31, 2008 totaled $81 million and consisted of estimated recovery amounts, using a probability-weighted methodology, from equipment salvage and potential resale activities. Cumulative net cash proceeds through December 31, 2008 from the sale of the impaired assets total $169 million.

Subsidiaries of EFH Corp. have terminated all of the equipment orders, with the exception of one purchase order for a boiler that is expected to be resold, and the air permit applications related to the eight units were formally withdrawn from the TCEQ in October 2007 after the close of the Merger. The net charges arising from cancellation of this development program have been classified in other deductions and are reported in the results of the Competitive Electric segment.

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6. IMPAIRMENT OF NATURAL GAS-FUELED GENERATION FLEET

In the fourth quarter of 2008, EFH Corp. performed an evaluation of its natural gas-fueled generation fleet for impairment in accordance with the requirements of SFAS 144, which provides that long-lived assets should be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The impairment test was triggered by a determination that it was more likely than not that certain generation units would be retired or mothballed (idled) earlier than previously expected. The natural gas-fueled generation units are generally operated to meet peak demands for electricity and the fleet is tested for impairment as an asset group. As a result of the evaluation, it was determined that an impairment existed, and a charge of $229 million ($147 million after-tax) was recorded to write down the assets to fair value of approximately $28 million, which was determined based on discounted estimated future cash flows.

In 2006, EFH Corp. also performed an evaluation of its natural gas-fueled generation fleet for impairment in accordance with the requirements of SFAS 144. In consideration of the lignite/coal-fueled generation plant development program then underway, among other factors, EFH Corp. determined at that time that it was more likely than not that its natural gas-fueled generation units would be sold or otherwise disposed of before the end of their previously estimated useful lives and should be tested for impairment. As a result, it was determined that an impairment existed, and a charge of $198 million ($129 million after-tax) was recorded in 2006 to write down the assets to fair value, which was determined based on discounted estimated future cash flows.

The impairments in both years were reported in other deductions in the Competitive Electric segment.

7. CUSTOMER APPRECIATION BONUS

In 2006, EFH Corp. announced a special customer appreciation bonus program. Under the program, a $100 bonus was provided to residential customers receiving service as of October 29, 2006 and living in areas where EFH Corp. offered its then-regulated rate, which expired January 1, 2007 in accordance with applicable law. Eligible customers were not required to continue to receive service from EFH Corp. to receive the bonus. The bonus was paid out in the form of credits on customer bills, with approximately $40 million paid out in 2006 and the balance fully settled in 2007. The bonus program resulted in a charge of $162 million ($105 million after-tax) in 2006. The charge was recorded as a reduction to revenue in the Competitive Electric segment.

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8. STIPULATION APPROVED BY THE PUCT

Oncor and Texas Holdings agreed to the terms of a stipulation, which was conditional upon completion of the Merger, with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. In February 2008, the PUCT entered an order approving the stipulation. The PUCT issued a final order on rehearing in April 2008 that has been appealed to District Court.

In addition to commitments Oncor made in its filings in the PUCT review, the stipulation included the following provisions, among others:

• Oncor provided a one-time $72 million refund to its REP customers in the September 2008 billing cycle. The refund was in the form of a credit on distribution fee billings. The liability for the refund was recorded as part of purchase accounting.

• Consistent with the 2006 cities rate settlement (see Note 9), Oncor filed a system-wide rate case in June 2008 based on a test-year ended December 31, 2007.

• Oncor agreed not to request recovery of approximately $56 million of regulatory assets related to self-insurance reserve costs and 2002 restructuring expenses. These regulatory assets were eliminated as part of purchase accounting.

• The dividends paid by Oncor will be limited through December 31, 2012, to an amount not to exceed Oncor’s net income (determined in accordance with GAAP, subject to certain defined adjustments) for the period beginning October 11, 2007 and ending December 31, 2012 and are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.

• Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions.

• Oncor committed to an additional $100 million in spending over the five-year period ending December 31, 2012 on demand-side management or other energy efficiency initiatives. These additional expenditures will not be recoverable in rates, and this amount was recorded as a regulatory liability as part of purchase accounting and consistent with SFAS 71.

• If Oncor’s credit rating is below investment grade with two or more rating agencies, TCEH will post a letter of credit in an amount of $170 million to secure TXU Energy’s payment obligations to Oncor.

• Oncor agreed not to request recovery of the $4.9 billion of goodwill resulting from purchase accounting or any future impairment of the goodwill in its rates.

9. CITIES RATE SETTLEMENT IN 2006

In January 2006, Oncor agreed with a steering committee representing 108 cities in Texas (Cities) to defer the filing of a system-wide rate case with the PUCT to no later than July 1, 2008 (based on a test year ending December 31, 2007). Oncor filed the rate case with the PUCT in June 2008. Oncor extended the benefits of the agreement to 292 nonlitigant cities. The agreements provided that Oncor would make payments to participating cities totaling approximately $70 million, including incremental franchise taxes.

This amount was recognized in earnings of the Regulated Delivery segment over the period from May 2006 through June 2008. Amounts recognized totaled $23 million in 2008, $8 million for the period October 11, 2007 through December 31, 2007, $25 million for the period January 1, 2007 through October 10, 2007, and $18 million in 2006, of which $13 million, $6 million, $20 million and $13 million, respectively, are reported in other deductions (see Note 13) and franchise and revenue-based taxes.

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10. ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES (FIN 48)

Effective January 1, 2007, EFH Corp. adopted FIN 48. FIN 48 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. applied FSP FIN 48-1 to determine if each tax position was effectively settled for the purpose of recognizing previously uncertain tax positions. EFH Corp. completed its review and assessment of uncertain tax positions and in the 2007 Predecessor period recorded a net benefit to retained earnings and a decrease to noncurrent liabilities of $33 million in accordance with the new accounting rule.

EFH Corp. and its subsidiaries file 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, 2003 are complete. In the fourth quarter 2008, EFH Corp. was notified of the commencement of the IRS audit of tax years 2003 to 2006. The audit is expected to require two years to complete. Texas franchise tax return periods under examination or still open for examination range from 2003 to 2007.

During the third quarter of 2008, EFH Corp. participated in negotiations with the IRS regarding the 2002 worthlessness loss associated with its discontinued Europe business and has reduced the liability for uncertain tax positions to reflect the most likely settlement of the issue. The reduction in the liability of approximately $375 million was largely offset by a reduction of deferred tax assets related to alternative minimum tax. The conclusion of issues contested from the 1997-2002 audit, including Europe, is not expected to occur prior to 2010.

EFH Corp. classifies interest and penalties related to uncertain tax positions as income tax expense. The amount of interest and penalties included in income tax expense totaled $88 million in 2008, $12 million for the period October 11, 2007 through December 31, 2007 and $43 million for the period January 1, 2007 through October 10, 2007. Noncurrent liabilities included a total of $198 million and $105 million in accrued interest at December 31, 2008 and 2007, respectively. All interest amounts are after-tax.

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, 2008 and 2007:

	2008			2007
Balance at January 1, excluding interest and penalties	$	1,834		$	1,770
Additions based on tax positions related to prior years		124			97
Reductions based on tax positions related to prior years		(451	)		(124	)
Additions based on tax positions related to the current year		33			101
Settlements with taxing authorities		43			(10	)
Reductions related to the lapse of the tax statute of limitations		—			—
Balance at December 31, excluding interest and penalties	$	1,583		$	1,834

Of the balance at December 31, 2008, $1.411 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 would 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, liabilities recorded would be reduced by $138 million, resulting in increased income from continuing operations and a favorable impact on the effective tax rate.

EFH Corp. filed a claim in 2006 for refund of income taxes and related interest paid in 2005 associated with IRS audits of 1993 and 1994 tax returns of a discontinued operation. The expected refund was recognized in the adoption of FIN 48. The carrying amount related to the claim, which is classified as a current income tax receivable as of December 31, 2008, consists of $43 million of tax and approximately $51 million of interest. The refund was received in February 2009 in an amount substantially as expected.

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EFH Corp. does not expect the total amount of liabilities recorded related to uncertain tax positions will significantly increase or decrease within the next 12 months.

11. TEXAS MARGIN TAX

In May 2006, the Texas legislature enacted a new law that reformed the Texas franchise tax system and replaced it with a new tax system, referred to as the Texas margin tax. The Texas margin tax has been determined to be an income tax for accounting purposes. In accordance with the provisions of SFAS 109, which require that deferred tax assets and liabilities be adjusted for the effects of new income tax legislation in the period of enactment, EFH Corp. estimated and recorded a net deferred tax charge of $44 million in 2006.

In June 2007, an amendment to this law was enacted that included clarifications and technical changes to the provisions of the tax calculation. In the 2007 Predecessor period, EFH Corp. recorded a deferred tax benefit of $70 million, essentially all of which related to changes in the rate at which a tax credit is calculated as specified in the new law. This estimated benefit is based on the Texas margin tax law in its current form and the current guidance issued by the Texas Comptroller of Public Accounts.

The Texas margin tax was effective for returns filed on or after January 1, 2008. EFH Corp.’s return filed during 2008 was based upon the taxable margin earned in 2007. Beginning January 1, 2007, margin tax has been accrued based on revenues reduced by deductions provided in the amended law.

Of the total 2006 net deferred tax charge, $43 million was recognized as a deferred tax charge in the Competitive Electric segment results and $1 million was recognized as a deferred tax charge in the Corporate and Other nonsegment results. Of the total 2007 deferred tax benefit, $32 million was recognized in the Competitive Electric segment results and $38 million was recognized in the Corporate and Other nonsegment results.

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12. INCOME TAXES

The components of EFH Corp.’s income tax expense (benefit) applicable to continuing operations are as follows:

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Current:
US Federal	$	(46	)	$	52		$	400		$	500
State		52			10			20			5
Non-US		—			—			—			1
Total		6			62			420			506
Deferred:
US Federal		(482	)		(722	)		12			715
State		10			(12	)		(108	)		63
Total		(472	)		(734	)		(96	)		778
Amortization of investment tax credits		(5	)		(1	)		(15	)		(21	)
Total	$	(471	)	$	(673	)	$	309		$	1,263

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

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Income from continuing operations before income taxes	$	(10,469	)	$	(2,034	)	$	1,008		$	3,728
Income taxes at the US federal statutory rate of 35%	$	(3,664	)	$	(712	)	$	353		$	1,305
Nondeductible goodwill impairment		3,101
Lignite depletion allowance		(29	)		(5	)		(30	)		(51	)
Production activities deduction		—			10			(10	)		(14	)
Amortization of investment tax credits — net of deferred income tax effect		(5	)		(1	)		(12	)		(15	)
Amortization (under regulatory accounting) of statutory rate changes		2			—			2			(7	)
Medicare subsidy — other postretirement employee benefits		(6	)		(2	)		(6	)		(8	)
Nondeductible interest expense		11			1			—			—
Nondeductible losses (earnings) on benefit plans		9			(1	)		(6	)		(4	)
State income taxes, net of federal tax benefit		39			(3	)		16			6
Texas margin tax — deferred tax adjustments (Note 11)		—			—			(70	)		44
Nondeductible merger transaction costs		—			23			—			—
Deferred tax adjustments		—			—			25			—
Accrual of interest		59			12			43			9
Other, including audit settlements		12			5			4			(2	)
Income tax expense	$	(471	)	$	(673	)	$	309		$	1,263
Effective tax rate		4.5	%		33.1	%		30.7	%		33.9	%

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Deferred Income Tax Balances

Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2008 and 2007 balance sheet dates are as follows:

	Successor
	December 31, 2008							December 31, 2007
	Total		Current			Noncurrent		Total		Current			Noncurrent
Deferred Income Tax Assets
Alternative minimum tax credit carryforwards	$	447	$	—		$	447	$	789	$	—		$	789
Employee benefit liabilities		173		33			140		456		29			427
Net operating loss (NOL) carryforwards		523		—			523		194		—			194
Regulatory liabilities		—		—			—		111		—			111
Unfavorable purchase and sales contracts		259		—			259		269		—			269
Other		260		44			216		133		11			122
Total		1,662		77			1,585		1,952		40			1,912
Deferred Income Tax Liabilities
Property, plant and equipment		4,375		—			4,375		5,787		—			5,787
Basis difference in Oncor partnership		1,192		—			1,192		—		—			—
Commodity contracts and interest rate swaps		645		31			614		224		31			193
Regulatory assets		—		—			—		680		—			680
Identifiable intangible assets		1,049		—			1,049		1,580		—			1,580
Debt fair value discounts		257		—			257		301		—			301
Other		26		2			24		35		—			35
Total		7,544		33			7,511		8,607		31			8,576
Net Deferred Income Tax (Asset) Liability	$	5,882	$	(44	)	$	5,926	$	6,655	$	(9	)	$	6,664

At December 31, 2008 EFH Corp. had $447 million of alternative minimum tax credit carryforwards (AMT) available to offset future tax payments. The AMT credit carryforwards have no expiration date. At December 31, 2008, EFH Corp. had net operating loss (NOL) carryforwards for federal income tax purposes of $1.493 billion that expire between 2023 and 2028. The NOL carryforwards can be used to offset future taxable income. EFH Corp. fully expects to utilize all of its NOL carryforwards prior to their expiration dates.

The component of deferred income tax liabilities referred to as “basis difference in Oncor partnership” arose as a result of the minority interests sale (see Note 18) at which time Oncor became a partnership for US federal income tax purposes. The amount of this basis difference at the date of the transaction represented EFH Corp.’s interest (approximately 80%) in the net deferred tax liabilities related to Oncor’s individual operating assets and liabilities. The remaining net deferred tax liabilities associated with Oncor ($299 million at December 31, 2008) that are attributable to the minority interests have been reclassified as other noncurrent liabilities (see Note 28).

The income tax effects of the components included in accumulated other comprehensive income at December 31, 2008 and 2007 totaled a net deferred tax asset of $207 and $91 million, respectively.

See Note 10 for discussion regarding accounting for uncertain tax positions (FIN 48).

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13. OTHER INCOME AND DEDUCTIONS

	Successor					Predecessor
	Year Ended December 31, 2008		Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Other income:
Gain on contract settlement (a)	$	—	$	—		$	—		$	26
Amortization of gain on sale of TXU Fuel (b)		—		—			36			47
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting (Note 2)		44		10			—			—
Insurance recoveries (c)		21		—			—			17
Net gain on sale of other properties and investments (d)		4		1			4			22
Reduction of insurance reserves related to discontinued operations		—		1			7			—
Penalty received for nonperformance under a coal transportation agreement		—		—			6			—
Mineral rights royalty income		4		1			8			—
Other		7		1			8			9
Total other income	$	80	$	14		$	69		$	121
Other deductions:
Impairment of trade name intangible asset (Note 3)	$	481	$	—		$	—		$	—
Impairment of emission allowances intangible assets (Note 3)		501		—			—			—
Charge for impairment of natural gas-fueled generation fleet (Note 6)		229		—			—			198
Charge related to Lehman bankruptcy (e)		26		—			—			—
Professional fees incurred related to the Merger (f)		14		51			39			—
Net charges related to cancelled development of generation facilities (Note 5)		12		2			755			—
Charge related to termination of rail car lease (g)		—		—			10			—
Other asset writeoffs (h)		2		—			34			4
Credit related to impaired leases (i)		—		—			(48	)		—
Equity losses - unconsolidated affiliates		—		—			1			14
Costs related to 2006 cities rate settlement (Note 9)		13		6			20			13
Litigation/regulatory settlements		10		—			5			9
Expenses related to cancelled joint venture at Oncor		—		—			12			7
Ongoing pension and other postretirement benefit costs related to discontinued businesses		2		(2	)		7			23
Other		11		4			6			1
Total other deductions	$	1,301	$	61		$	841		$	269

(a) In 2006, EFH Corp. recorded income of $26 million upon settlement of a contract dispute related to antenna site rentals by a telecommunication company (reported in Corporate and Other activities).

(b) As part of the 2004 sale of the assets of TXU Fuel, TCEH entered into a transportation agreement with the new owner, intended to be market-price based, to transport natural gas to TCEH’s generation plants. Because of the continuing involvement in the business through the transportation agreement, the pretax gain of $375 million related to the sale was deferred and being recognized over the eight-year life of the transportation agreement, and the business was not accounted for as a discontinued operation. The remaining $218 million deferred gain was eliminated as part of purchase accounting related to the Merger (reported in Corporate and Other activities).

146

(c) 2008 amount represents insurance recovery for damage to mining equipment (reported in Competitive Electric segment). 2006 amount primarily represents additional insurance recoveries recorded related to the 2005 settlement of the shareholders' litigation (reported in Corporate and Other activities).

(d) The 2006 period includes $12 million in gains on land sales (substantially all reported in the Competitive Electric segment) and a $10 million gain related to the sale of mineral interests (reported in Corporate and Other activities).

(e) Represents reserve established against amounts due (excluding termination related costs) from subsidiaries of Lehman Brothers Holdings Inc. arising from commodity hedging and trading activities. There are no open positions with these subsidiaries. (Reported in Competitive Electric segment.)

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

(g) Represents costs associated with termination and refinancing of a rail car lease (reported in the Competitive Electric segment).

(h) Predecessor period of 2007 includes $30 million of previously deferred costs, consisting primarily of professional fees for tax, legal and other advisory services, in connection with certain previously anticipated strategic transactions (including expected financings) that were no longer expected to be consummated as a result of the Merger (reported in Corporate and Other activities).

(i) In 2004, EFH Corp. recorded a charge of $157 million for leases of certain natural gas-fueled combustion turbines, net of estimated sublease revenues, that were no longer operated for its own benefit. In the third quarter of 2007, a $48 million reduction in the related liability was recorded to reflect new subleases entered into in October 2007 (reported in the Competitive Electric segment results). The remaining $59 million liability was eliminated as part of purchase accounting as EFH Corp. intends to operate these assets for its own benefit.

14. TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

Sale of Receivables

Subsidiaries of EFH Corp. engaged in retail sales of electricity participate in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with SFAS 140. Under the program, such subsidiaries (originators) sell trade accounts receivable to TXU Receivables Company, which is a special purpose entity created for the purpose of purchasing receivables from the originators and is a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp. TXU Receivables Company sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions (the funding entities).

The maximum amount currently available under the accounts receivable securitization program is $700 million, and the program funding was $416 million at December 31, 2008. The amount of customer deposits held by the originators can reduce the amount of undivided interests that can be sold, thus reducing funding available under the program, during periods in which TCEH’s long-term senior unsecured debt rating is lower than investment grade. Funding availability for all originators can be reduced by 100% of the originators’ customer deposits if TCEH’s credit rating is lower than Ba3/BB-; 50% if TCEH’s credit rating is between Ba3/BB- and Ba1/BB+; and zero % if TCEH’s credit rating is at least Baa3/BBB-. The originators’ customer deposits, which totaled $108 million, reduced funding availability as of December 31, 2008 because TCEH’s credit ratings were lower than Ba3/BB-.

All new trade receivables under the program generated by the originators are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. 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 subordinated notes payable to the originators for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originators that was funded by the sale of the undivided interests. The balance of the subordinated notes payable, which is eliminated in consolidation, totaled $268 million and $296 million at December 31, 2008 and 2007, respectively.

147

The discount from face amount on the purchase of receivables from the originators principally funds program fees paid to the funding entities. The program fees, which are also referred to as losses on sale of the receivables under SFAS 140, consist primarily of interest costs on the underlying financing. The discount also funds a servicing fee paid by TXU Receivables Company to EFH Corporate Services Company, a direct wholly-owned subsidiary of EFH Corp., which serves as the collection agent of the receivables. EFH Corp. maintains collection responsibilities through EFH Corporate Services Company in order to efficiently service and maintain the integrity of the receivables portfolio. The servicing fee compensates EFH Corporate Services Company for serving as the collection agent of the receivables. Responsibilities of the collection agent include, but are not limited to, maintaining detailed accounts receivable collection records and interfacing with customers regarding payment options and terms of current and past-due accounts. In the event EFH Corporate Services Company is relieved of its duties as collection agent because of default under the program, the funding entities assume responsibility as the collection agent.

The program fees represent essentially all the net incremental costs of the program on a consolidated basis and are reported in SG&A expenses. Fee amounts were as follows:

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Program fees	$	25		$	9		$	32		$	40
Program fees as a percentage of average funding (annualized)		5.2	%		9.5	%		6.4	%		5.8	%
Servicing fees	$	4		$	1		$	3		$	4

The accounts receivable balance reported in the December 31, 2008 consolidated balance sheet includes $684 million face amount of trade accounts receivable of TCEH subsidiaries in which undivided interests totaling $416 million have been sold by TXU Receivables Company. Funding under the program increased $53 million in 2008, decreased $264 million in 2007 and decreased $44 million in 2006. Funding increases or decreases under the program are reflected as operating cash flow activity in the statement of cash flows. The carrying amount of the retained interests in the accounts receivable balance approximated fair value due to the short-term nature of the collection period.

Activities of TXU Receivables Company were as follows:

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Cash collections on accounts receivable	$	6,393		$	1,538		$	6,251		$	8,503
Face amount of new receivables purchased		(6,418	)		(1,194	)		(6,628	)		(8,469	)
Discount from face amount of purchased receivables		29			9			35			44
Program fees paid		(25	)		(9	)		(32	)		(40	)
Servicing fees paid		(4	)		(1	)		(3	)		(4	)
Increase (decrease) in subordinated notes payable		(28	)		(120	)		305			10
Oncor’s repurchase of receivables previously sold		—			113			—			—
Operating cash flows used by (provided to) EFH Corp. under the program	$	(53	)	$	336		$	(72	)	$	44

In connection with the Merger, the accounts receivable securitization program was amended. Concurrently with the amendment, the financial institutions required that Oncor repurchase all of the receivables it had previously sold to TXU Receivables Company, which totaled $254 million. Oncor funded such repurchases through borrowings under its credit facility of $113 million, and a related subordinated note receivable from TXU Receivables Company in the amount of $141 million was canceled. Amounts related to Oncor’s trade accounts receivable for the period from January 1, 2007 through October 11, 2007 totaled $6 million in program fees and $27 million in operating cash flows provided, exclusive of the $113 million used by Oncor to repurchase its receivables at the time of the Merger. Subsequent to the Merger, only subsidiaries of TCEH participate in the accounts receivable securitization program.

148

The program may be terminated upon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds, and the financial institutions do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables, not separately to the receivables of each originator. In addition, the program may be terminated if TXU Receivables Company or EFH Corporate Services Company, as collection agent, shall default in any payment with respect to debt in excess of $50,000 in the aggregate for TXU Receivables Company and EFH Corporate Services Company, or if TCEH, any affiliate of TCEH acting as collection agent under the program other than EFH Corporate Services Company, any parent guarantor of an originator or any 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.

Upon termination of the program, cash flows would be delayed 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. The level of cash flows would normalize in approximately 16 to 30 days.

The subordinated notes issued by TXU Receivables Company are subordinated to the undivided interests of the financial institutions in the purchased receivables.

Trade Accounts Receivable

	Successor
	December 31,
	2008			2007
Gross wholesale and retail trade accounts receivable	$	1,705		$	1,494
Undivided interests in retail accounts receivable sold by TXU Receivables Company		(416	)		(363	)
Allowance for uncollectible accounts		(70	)		(32	)
Trade accounts receivable — reported in balance sheet	$	1,219		$	1,099

Gross trade accounts receivable at December 31, 2008 and 2007 included unbilled revenues of $505 million and $477 million, respectively.

149

Allowance for Uncollectible Accounts Receivable

Predecessor:
Allowance for uncollectible accounts receivable as of December 31, 2005	$	36
Increase for bad debt expense		68
Decrease for account write-offs		(80	)
Changes related to receivables sold		4
Other (a)		(15	)
Allowance for uncollectible accounts receivable as of December 31, 2006		13
Increase for bad debt expense		46
Decrease for account write-offs		(54	)
Changes related to receivables sold		26
Allowance for uncollectible accounts receivable as of October 10, 2007		31
Successor:
Allowance for uncollectible accounts receivable as of October 11, 2007		31
Increase for bad debt expense		13
Decrease for account write-offs		(12	)
Allowance for uncollectible accounts receivable as of December 31, 2007		32
Increase for bad debt expense		81
Decrease for account write-offs		(69	)
Charge related to Lehman bankruptcy		26
Allowance for uncollectible accounts receivable as of December 31, 2008	$	70

(a) Reflects an allowance established in 2005 for a coal contract dispute that was reversed upon settlement in 2006. (Allowance and subsequent reversal are recorded in other deductions.)

150

15. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

At December 31, 2008, EFH Corp. and its subsidiaries had outstanding short-term borrowings of $1.237 billion at a weighted average interest rate of 3.41%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $900 million for TCEH and $337 million for Oncor.

At December 31, 2007, EFH Corp. and its subsidiaries had outstanding short-term borrowings of $1.718 billion at a weighted average interest rate of 5.39%, excluding certain customary fees, at the end of the period. Borrowings under credit facilities totaled $1.280 billion for Oncor and $438 million for TCEH.

Credit Facilities

EFH Corp.’s credit facilities with cash borrowing and/or letter of credit availability at December 31, 2008 are presented below. The facilities are all senior secured facilities of the authorized borrower.

Authorized Borrowers and Facility	Maturity Date	At December 31, 2008
		Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Delayed Draw Term Loan Facility (a)	October 2014	$	4,100	$	—	$	3,562	$	522
TCEH Revolving Credit Facility (b)	October 2013		2,700		7		900		1,767
TCEH Letter of Credit Facility (c)	October 2014		1,250		—		1,250		—
Subtotal TCEH (d)		$	8,050	$	7	$	5,712	$	2,289
TCEH Commodity Collateral Posting Facility (e)	December 2012		Unlimited	$	—	$	—		Unlimited
Oncor Revolving Credit Facility (f)	October 2013	$	2,000	$	—	$	337	$	1,508

(a) Facility to be used during the two-year period commencing on October 10, 2007 to fund expenditures for constructing certain new generation facilities and environmental upgrades of existing generation facilities, including previously incurred expenditures not yet funded under this facility. Borrowings are classified as long-term debt. Availability amount excludes $9 million of undrawn commitments from a subsidiary of Lehman Brothers Holding Inc. (Lehman) that has filed for bankruptcy under Chapter 11 of the US Bankruptcy Code and $7 million of requested draws that have not been funded by the Lehman subsidiary.

(b) Facility to be used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount includes $144 million of undrawn commitments from the Lehman subsidiary that is only available from the fronting banks in the form of letters of credit and excludes $26 million of requested draws that have not been funded by the Lehman subsidiary.

(c) Facility to be 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, all of which were drawn at the closing of the Merger and are classified as long-term debt, have been retained as restricted cash. Letters of credit totaling $760 million issued as of December 31, 2008 are supported by the restricted cash, and the remaining letter of credit availability totals $490 million.

(d) Pursuant to PUCT rules, TCEH is required to maintain available capacity under its credit facilities to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at December 31, 2008, the total availability under the TCEH credit facilities should be further reduced by $266 million.

(e) Revolving facility to be used to fund cash collateral posting requirements for specified volumes of natural gas hedges. As of December 31, 2008, cash borrowings under the facility had been repaid. See “TCEH Senior Secured Facilities” below for additional information.

(f) Facility to be used by Oncor for its general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount excludes $142 million of undrawn commitments from the Lehman subsidiary and $13 million of requested draws that have not been funded by the Lehman subsidiary.

151

Long-Term Debt

At December 31, 2008 and 2007, the long-term debt of EFH Corp. consisted of the following:

	Successor
	December 31, 2008			December 31, 2007
TCEH
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 (a)		16			16
7.700% Fixed Series 1999C due March 1, 2032		50			50
8.250% Fixed Series 2001A due October 1, 2030		71			—
2.300% Floating Series 2001A due October 1, 2030 (b)		—			71
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011 (a)		217			217
8.250% Fixed Series 2001D-1 due May 1, 2033		171			—
2.300% Floating Series 2001D-1 due May 1, 2033 (b)		—			171
1.400% Floating Series 2001D-2 due May 1, 2033 (c)		97			97
2.500% Floating Taxable Series 2001I due December 1, 2036 (d)		62			62
1.400% Floating Series 2002A due May 1, 2037 (c)		45			45
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (a)		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 (a)		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 (a)		91			91
5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011 (a)		107			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 (e)		(161	)		(175	)
Senior Secured Facilities:
5.456% TCEH Initial Term Loan Facility maturing October 10, 2014 (f)(g)		16,244			16,409
5.150% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (f)(g)		3,562			2,150
3.986% TCEH Letter of Credit Facility maturing October 10, 2014 (g)		1,250			1,250
0.449% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (h)		—			382
Other:
10.25% Fixed Senior Notes due November 1, 2015 (i)		3,000			3,000
10.25% Fixed Senior Notes Series B due November 1, 2015 (i)		2,000			2,000
10.50 / 11.25% Senior Toggle Notes due November 1, 2016 (i)		1,750			1,750
6.125% Fixed Senior Notes due March 15, 2008		—			3
7.000% Fixed Senior Notes due March 15, 2013		5			5
7.100% Promissory Note due January 5, 2009		65			65
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		67			78
Capital lease obligations		159			161
Unamortized fair value discount (e)		(6	)		(9	)
Total TCEH	$	29,470		$	28,604

152

	Successor
	December 31, 2008			December 31, 2007
EFC Holdings
9.580% Fixed Notes due in semiannual installments through December 4, 2019	$	55		$	59
8.254% Fixed Notes due in quarterly installments through December 31, 2021		53			56
3.993% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (g)		1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037		8			8
Unamortized fair value discount (e)		(12	)		(14	)
Total EFC Holdings		105			110
EFH Corp. (parent entity)
10.875% Fixed Senior Notes due November 1, 2017 (i)		2,000			2,000
11.25 / 12.00% Senior Toggle Notes due November 1, 2017 (i)		2,500			2,500
6.375% Fixed Senior Notes Series C due January 1, 2008		—			200
4.800% Fixed Senior Notes Series O due November 15, 2009		3			3
5.550% Fixed Senior Notes Series P due November 15, 2014		1,000			1,000
6.500% Fixed Senior Notes Series Q due November 15, 2024		750			750
6.550% Fixed Senior Notes Series R due November 15, 2034		750			750
8.820% Building Financing due semiannually through February 11, 2022 (j)		80			88
Unamortized fair value premium related to Building Financing (e)		22			24
Unamortized fair value discount (e)		(661	)		(714	)
Total EFH Corp.		6,444			6,601
Oncor (k)
6.375% Fixed Senior Notes due May 1, 2012		700			700
5.950% Fixed Senior Notes due September 1, 2013		650			—
6.375% Fixed Senior Notes due January 15, 2015		500			500
6.800% Fixed Senior Notes due September 1, 2018		550			—
7.000% Fixed Debentures due September 1, 2022		800			800
7.000% Fixed Senior Notes due May 1, 2032		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
7.500% Fixed Senior Notes due September 1, 2038		300			—
Unamortized discount		(16	)		(15	)
Total Oncor		4,334			2,835
Oncor Electric Delivery Transition Bond Company LLC (l)
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		54			93
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		130			130
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		145			145
3.520% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2009		39			99
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		221			221
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		290			290
Total Oncor Electric Delivery Transition Bond Company LLC		879			978
Unamortized fair value discount related to transition bonds (e)		(9	)		(12	)
Total Oncor consolidated		5,204			3,801
Total EFH Corp. consolidated		41,223			39,116
Less amount due currently (m)		(385	)		(513	)
Total long-term debt	$	40,838		$	38,603

(a) 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.

(b) Interest rates in effect at March 31, 2008. These series were remarketed in June 2008, resulting in a fixed rate to maturity.

(c) Interest rates in effect at December 31, 2008. 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.

(d) Interest rate in effect at December 31, 2008. 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.

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

(f) Interest rate swapped to fixed on $17.55 billion principal amount.

(g) Interest rates in effect at December 31, 2008.

(h) Interest rates in effect at December 31, 2008, excluding quarterly maintenance fee discussed below. See “Credit Facilities” above for more information.

(i) Additional Interest will be payable on these notes on May 1, 2009 per the discussion below under “TCEH Notes Issued Subsequent to the Merger” and “EFH Corp. Notes Issued Subsequent to the Merger.”

(j) This financing is secured with a $121 million letter of credit.

(k) Secured with first priority lien as discussed under “Oncor Revolving Credit Facility” below.

(l) These bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset.

(m) Includes $3 million and $200 million at December 31, 2008 and 2007, respectively, representing debt of the EFH Corp. parent entity.

153

Debt-Related Activity in 2008— Repayments of long-term debt in 2008 totaling $1.167 billion represented principal payments at scheduled maturity dates as well as the remarketing of $242 million principal amount of pollution control revenue bonds discussed below, repayment of $413 million of borrowings under the TCEH Commodity Collateral Posting Facility, which fully repaid borrowings under the facility, and other repayments totaling $48 million, principally related to leases. Payments at scheduled maturity dates included $200 million of EFH Corp. senior notes, $165 million repaid under the TCEH Initial Term Loan Facility, and $99 million of Oncor transition bond principal payments.

Increases in long-term debt during 2008 totaling $3.185 billion consisted of issuances of senior secured notes issued by Oncor with an aggregate principal amount of $1.500 billion (see discussion below under “Oncor Senior Secured Notes”), borrowings under the TCEH Delayed Draw Term Loan Facility of $1.412 billion to fund expenditures related to the development of new generation facilities and the environmental retrofit program for existing lignite/coal-fueled generation facilities, the remarketing of $242 million principal amount of pollution control revenue bonds discussed immediately below and $31 million of additional borrowings under the TCEH Commodity Collateral Posting Facility.

In June 2008, TCEH remarketed the Brazos River Authority Pollution Control Revenue Bonds Series 2001A due in October 2030 and Series 2001D-1 due in May 2033 with aggregate principal amounts of $71 million and $171 million, respectively. The bonds were previously in a floating rate mode that reset weekly and were backed by two letters of credit in an aggregate amount of $247 million. As a result of the remarketing, the bonds were fixed to maturity at an interest rate of 8.25%, and the two letters of credit were cancelled. The bonds are redeemable at par beginning July 1, 2018 and are redeemable with a make-whole premium prior to July 1, 2018. These bonds were remarketed with a covenant package similar to the notes discussed below under “TCEH Notes Issued Subsequent to the Merger.”

EFH Corp. and TCEH have the option every six months until November 1, 2012, at their election, to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments. The companies elected to do so for the May 1, 2009 interest payment date as an efficient and cost-effective method to further enhance liquidity, in light of the substantial dislocation in the financial markets. Moreover, the incremental liquidity obtained by using the PIK feature of the toggle notes for this specific payment period more than offsets the liquidity that was effectively lost as a result of the default by affiliates of Lehman under TCEH’s Senior Secured Facilities.

EFH Corp. will make its May 2009 interest payment by using the PIK feature of the EFH Corp. Toggle Notes. The election will increase the interest rate on the toggle notes from 11.25% to 12.00% during the interest period covered by the PIK election and require EFH Corp. to issue an additional $150 million principal amount of EFH Corp. Toggle Notes on May 1, 2009. In addition, the election will increase liquidity by an amount equal to approximately $141 million, constituting the amount of cash interest that otherwise would have been payable on May 1, 2009, and increase the expected annual cash interest expense by approximately $17 million, constituting the additional cash interest that would be payable with respect to the $150 million of additional toggle notes.

Similarly, TCEH will make its May 2009 interest payment by using the PIK feature of the TCEH Toggle Notes. The election will increase the interest rate on the TCEH Toggle Notes from 10.50% to 11.25% during the interest period covered by the PIK election and require TCEH to issue an additional approximately $98.5 million principal amount of TCEH Toggle Notes on May 1, 2009. In addition, the election will increase liquidity by an amount equal to approximately $92 million, constituting the amount of cash interest that otherwise would have been payable on May 1, 2009, and increase the expected annual cash interest expense by approximately $10 million, constituting the additional cash interest that would be payable with respect to the $98.5 million of additional toggle notes.

154

Maturities— Long-term debt maturities as of December 31, 2008 are as follows (includes Oncor’s transition bond semi-annual payments):

Year
2009 (a)	$	371
2010		335
2011		759
2012		1,051
2013		1,066
Thereafter (a)		38,325
Unamortized fair value premium		22
Unamortized fair value discount (b)		(849	)
Unamortized discount		(16	)
Capital lease obligations		159
Total	$	41,223

(a) Long-term debt maturities for EFH Corp. (parent entity) totals $3 million and $7.0 billion for 2009 and thereafter, respectively.

(b) Unamortized fair value discount for EFH Corp. (parent entity) totals $(661) million.

155

Long-Term Debt-Related Activity in 2007—EFH Corp. and its subsidiaries issued, reacquired or made scheduled principal payments on long-term debt in 2007 as follows (all amounts presented are principal):

	Successor										Predecessor
	Post-Merger					Merger-Date
	Issuances		Repayments / Repurchases			Issuances		Repayments / Repurchases			Issuances		Repayments / Repurchases
TCEH:
Senior secured facilities:
Initial term loan facility	$	—	$	(41	)	$	16,450	$	—		$	—	$	—
Delayed draw term loan facility		—		—			2,150		—			—		—
Letter of credit facility		—		—			1,250		—			—		—
Commodity collateral posting facility		—		—			382		—			—		—
Senior unsecured interim facilities:
Initial cash-pay loans		—		(5,000	)		5,000		—			—		—
Initial toggle loans		—		(1,750	)		1,750		—			—		—
Senior notes:
Senior cash-pay notes		5,000		—			—		—			—		—
Senior toggle notes		1,750		—			—		—			—		—
Floating rate senior notes (a)		—		—			—		(1,000	)		1,000		—
Fixed senior notes		—		—			—		(1,242	)		—		—
Secured promissory note		—		—			—		—			65		—
Pollution control revenue bonds		—		—			—		—			—		(143	)
Capital lease obligations		16		(4	)		—		—			59		(8	)
Other long-term debt		—		—			—		—			—		(7	)
EFC Holdings:
Fixed senior debentures		—		—			—		—			—		(10	)
Other long-term debt		—		(4	)		—		—			—		(2	)
EFH Corp.:
Senior unsecured interim facilities:
Initial cash-pay loans		—		(2,000	)		2,000		—			—		—
Initial toggle loans		—		(2,500	)		2,500		—			—		—
Senior notes:
Senior cash-pay notes		2,000		—			—		—			—		—
Senior toggle notes		2,500		—			—		—			—		—
Fixed senior notes		—		—			—		(997	)		—		—
Floating convertible senior notes		—		—			—		(25	)		—		—
Other long-term debt		—		—			—		—			—		(11	)
Oncor:
Floating rate senior notes (a)		—		—			—		(800	)		800		—
Fixed debentures		—		—			—		—			—		(200	)
Transition bonds		—		(32	)		—		—			—		(64	)
Total	$	11,266	$	(11,331	)	$	31,482	$	(4,064	)	$	1,924	$	(445	)

(a) Notes were subject to mandatory redemption upon closing of the Merger.

Convertible Senior Notes— At December 31, 2006, EFH Corp. had $25 million principal amount outstanding of its Floating Rate Convertible Senior Notes due 2033. In conjunction with the Merger, a supplemental indenture was executed and provided that the previously outstanding EFH Corp. Floating Convertible Senior Notes became payable in cash at a fixed conversion rate of $4,274.05 per $1,000 principal amount of the Senior Notes. On October 25, 2007, substantially all of these notes (approximately $24.7 million) were converted and redeemed.

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Other Debt-Related Activity in 2007— In September 2007, EFH Corp. commenced offers to purchase and consent solicitations with respect to $1.0 billion in aggregate principal amount of EFH Corp.’s outstanding 4.80% Series O Senior Notes due 2009, $250 million in aggregate principal amount of TCEH’s outstanding 6.125% Senior Notes due 2008 and $1.0 billion in aggregate principal amount of TCEH’s outstanding 7.000% Senior Notes due 2013. The offers were contingent upon the closing of the Merger. In October 2007, EFH Corp. purchased an aggregate of $997 million, $247 million and $995 million principal amounts of these notes, respectively, for $1.005 billion, $248 million and $1.097 billion, respectively, excluding unpaid interest. Interest rate swaps related to $700 million principal amount of these notes were settled for $13 million upon extinguishment of the debt.

In September 2007, subsidiaries of EFH Corp. acquired certain assets of Alcoa Inc. relating to the operation of a lignite mine near Sandow, including partial ownership of the lignite reserves in the mine, for a purchase price of $135 million, including cash of $70 million and a promissory note of $65 million that was paid at maturity on January 5, 2009 at a fixed interest rate of 7.100%, which is reported as a current liability as of December 31, 2008.

In September 2007, TCEH refinanced an existing lease of rail cars, which had been accounted for as an operating lease, with a lease with another party that has been accounted for as a capital lease, resulting in $52 million reported as long-term debt. In late 2007, TCEH also entered into leases related to mining equipment that have been accounted for as capital leases totaling $23 million reported as long-term debt.

In May 2007, TCEH redeemed at par the Sabine River Authority of Texas Series 2006A and 2006B pollution control revenue bonds with aggregate principal amounts of $47 million and $46 million, respectively, and the Trinity River Authority of Texas Series 2006 pollution control revenue bonds with an aggregate principal amount of $50 million. All three bond series were issued in November 2006 in conjunction with the development of eight coal-fueled generation units, which has been cancelled. Restricted cash retained upon issuance of the bonds was used to fund substantially all of the redemption amounts.

In March 2007, TCEH and Oncor issued floating rate senior notes with an aggregate principal amount of $1.0 billion and $800 million, respectively, with a floating rate based on LIBOR plus 50 basis points for TCEH and 37.5 basis points for Oncor. The notes were to mature in September 2008, but in accordance with their terms, were redeemed upon closing of the Merger.

TCEH Senior Secured Facilities — Borrowings under the TCEH Initial Term Loan Facility, the TCEH Delayed Draw Term Loan Facility, the TCEH Revolving Credit Facility and the TCEH Letter of Credit Facility, which totaled $21.956 billion at December 31, 2008, bear interest at per annum rates equal to, at TCEH’s option, (i) adjusted LIBOR plus 3.50% or (ii) a base rate (the higher of (1) the prime rate as announced from time to time by the administrative agent of the facilities and (2) the federal funds effective rate plus 0.50%) plus 2.50%. There is a margin adjustment mechanism in relation to term loans, revolving loans and letter of credit fees under which the applicable margins may be reduced based on the achievement of certain leverage ratio levels; there was no such reduction based upon December 31, 2008 levels. The applicable rate on each facility as of December 31, 2008 is provided in the long-term debt table above and reflects LIBOR-based borrowings.

A commitment fee is payable quarterly in arrears and upon termination of the TCEH Revolving Credit Facility at a rate per annum equal to 0.50% of the average daily unused portion of such facility. The commitment fee is subject to reduction, based on the achievement of certain leverage ratio levels; there was no such reduction based upon December 31, 2008 levels.

With respect to the TCEH Delayed Draw Term Loan Facility, a commitment fee is payable quarterly in arrears and upon termination of the undrawn portion of the commitments of such facility at a rate per annum equal to, prior to October 10, 2008, 1.25% per annum, and thereafter, 1.50% per annum.

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Letter of credit fees under the TCEH Revolving Facility are payable quarterly in arrears and upon termination at a rate per annum equal to the spread over adjusted LIBOR under the TCEH Revolving Facility, less the issuing bank’s fronting fee. Letter of credit fees under the TCEH Letter of Credit Facility are equal to the difference between interest paid on each outstanding letter of credit at a rate of LIBOR plus 3.50% per annum and the interest earned on the total $1.25 billion TCEH Letter of Credit Facility restricted cash at a rate of LIBOR minus 0.12% per annum yielding a currently effective rate of 3.62% per annum on each outstanding letter of credit under that facility.

TCEH will pay a fixed quarterly maintenance fee of approximately $11 million through maturity for having procured the TCEH Commodity Collateral Posting Facility regardless of actual borrowings under the facility. In addition, TCEH will pay interest at LIBOR on actual borrowed amounts under the TCEH Commodity Collateral Posting Facility partially offset by interest earned on collateral deposits to counterparties.

The TCEH Senior Secured Facilities are unconditionally guaranteed jointly and severally on a senior secured basis, by EFC Holdings, and each existing and subsequently acquired or organized direct or indirect wholly-owned US restricted subsidiary of TCEH (other than certain subsidiaries as provided in the TCEH Senior Secured Facilities), subject to certain other exceptions.

The TCEH Senior Secured Facilities, including the guarantees thereof, certain commodity hedging transactions and the interest rate swaps described under “TCEH Interest Rate Hedges” below are secured by (a) substantially all of the current and future assets of TCEH and TCEH’s subsidiaries who are guarantors of such facilities as described above, and (b) pledges of the capital stock of TCEH and each current and future material wholly-owned restricted subsidiary of TCEH directly owned by TCEH or any guarantor.

The TCEH Senior Secured Facilities contain customary negative covenants, restricting, subject to certain exceptions, TCEH and TCEH’s restricted subsidiaries from, among other things:

• incurring additional debt;

• incurring additional liens;

• entering into mergers and consolidations;

• selling or otherwise disposing of assets;

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

• making acquisitions, investments, loans and advances, and

• paying or modifying certain subordinated and other material debt.

In addition, the TCEH Senior Secured Facilities contain a maintenance covenant that prohibits TCEH and its restricted subsidiaries from exceeding a maximum consolidated secured leverage ratio and to observe certain customary reporting requirements and other affirmative covenants.

The TCEH Initial Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of such facility ($41 million quarterly), with the balance payable on October 10, 2014. The TCEH Delayed Draw Term Loan Facility is required to be repaid in equal quarterly installments beginning on December 31, 2009 in an aggregate annual amount equal to 1% of the actual principal outstanding under the TCEH Delayed Draw Term Loan Facility as of such date, with the balance payable on October 10, 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time from and after the closing date until October 10, 2013. The TCEH Letter of Credit Facility will mature on October 10, 2014. The TCEH Commodity Collateral Posting Facility will mature on December 31, 2012.

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

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TCEH Notes Issued Subsequent to the Merger— Pursuant to an indenture entered into in October 2007 (the TCEH Indenture), TCEH and TCEH Finance (the Co-Issuers) issued and sold $3.0 billion aggregate principal amount of 10.25% Senior Notes due November 1, 2015. In December 2007 under a supplemental indenture, the Co-Issuers issued and sold $2.0 billion aggregate principal amount of 10.25% Series B Senior Notes due November 1, 2015. Interest on these notes (referred to as the TCEH Cash-Pay Notes) is payable in cash semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.25% per annum, and the first interest payment was made on May 1, 2008.

Pursuant to the supplemental indenture, the Co-Issuers also issued and sold $1.75 billion aggregate principal amount of 10.50%/11.25% Senior Toggle Notes due November 1, 2016. The initial interest payment on these notes (referred to as the TCEH Toggle Notes) was paid in cash. For any interest period thereafter until November 1, 2012, the Issuer may elect to pay interest on the notes, at the Issuer’s option (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new TCEH Toggle Notes (Payment-in-Kind or PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Interest on the notes is payable semi-annually in arrears on May 1 and November 1 of each year 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, and the first interest payment was made on May 1, 2008. See “Debt Related Activity in 2008” above for discussion of TCEH’s election to use the PIK option for the May 1, 2009 payment.

The $6.75 billion principal amount of notes issued under the TCEH Indenture and its supplement (the TCEH Cash-Pay Notes and the TCEH Toggle Notes) are collectively referred to as the TCEH Notes.

The TCEH Notes are fully and unconditionally guaranteed by TCEH’s direct parent, EFC Holdings (which owns 100% of TCEH and its subsidiary guarantors), and by each subsidiary that guarantees the TCEH Senior Secured Facilities (the TCEH Guarantors). The TCEH Notes are the Co-Issuers’ senior unsecured debt and rank senior in right of payment to any future subordinated indebtedness of the Co-Issuers, equally in right of payment with all of the Co-Issuers’ existing and future senior unsecured indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities of the Co-Issuers’ non-guarantor subsidiaries, including trade payables (other than indebtedness and liabilities owed to the Co-Issuers or the TCEH Guarantors). The TCEH Notes rank effectively junior in right of payment to all existing and future senior secured indebtedness of the Co-Issuers, including the TCEH Senior Secured Facilities to the extent of the value of the collateral securing such indebtedness.

The guarantees are joint and several guarantees of the TCEH Notes, are the TCEH Guarantors’ senior unsecured obligations and rank equal in right of payment with all existing and future senior unsecured indebtedness of the relevant TCEH Guarantor and senior in right of payment to any existing or future subordinated indebtedness of the relevant TCEH Guarantor. The guarantees rank effectively junior to all secured indebtedness of the TCEH Guarantors to the extent of the assets securing that indebtedness. EFC Holdings’ guarantee of the TCEH Notes ranks equally with its guarantee of the EFH Corp. Cash-Pay Notes and the EFH Corp. Toggle Notes (discussed below). The guarantees of the TCEH Notes are structurally junior to all indebtedness and other liabilities of the Co-Issuers’ subsidiaries that do not guarantee the notes.

The TCEH Indenture contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Co-Issuers’ and their restricted subsidiaries’ ability to:

• make restricted payments;

• incur debt and issue preferred stock;

• create liens;

• enter into mergers or consolidations;

• sell or otherwise dispose of certain assets;

• permit dividend and other payment restrictions on restricted subsidiaries, and

• engage in certain transactions with affiliates.

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The TCEH Indenture also contains customary events of default, including failure to pay principal or interest on the TCEH Notes or the guarantees when due, among others. If an event of default occurs under the TCEH Indenture, the trustee or the holders of at least 30% in principal amount of the Required Debt (as such term is defined in the TCEH Indenture) may declare the principal amount on the TCEH Notes to be due and payable immediately.

The Co-Issuers may redeem the TCEH Cash-Pay Notes, in whole or in part, at any time on or after November 1, 2011, or the TCEH Toggle Notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. In addition, before November 1, 2010, the Co-Issuers may redeem with the cash proceeds of certain equity offerings up to 35% of the aggregate principal amount of TCEH Cash-Pay Notes from time to time at a redemption price of 110.250% of the aggregate principal amount of the TCEH Cash-Pay Notes, plus accrued and unpaid interest, if any, or 110.500% of the aggregate principal amount of the TCEH Toggle Notes, plus accrued and unpaid interest, if any. The Co-Issuers may also redeem the TCEH Cash-Pay Notes at any time prior to November 1, 2011 or 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 a “make-whole” premium. Upon the occurrence of a change in control of TCEH, the Co-Issuers must offer to repurchase the TCEH Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

The TCEH Notes were issued in a private placement with registration rights. Notes having substantially identical terms as the TCEH Notes were registered with the SEC by the Co-Issuers in December 2008 as part of an offer to exchange freely tradable exchange notes for the TCEH Notes. The exchange offer was completed in January 2009. Because the exchange offer was not completed within 360 days after the issue date of the TCEH Notes (a TCEH Registration Default), the annual interest rate on the TCEH Notes increased for the period during which the TCEH Registration Default continued (October 26, 2008 to January 30, 2009 for the Senior Notes and November 30, 2008 to January 30, 2009 for the Series B Senior Notes and Senior Toggle Notes), resulting in incremental interest of $3.7 million.

EFH Corp. Notes Issued Subsequent to the Merger — Pursuant to an indenture entered into in October 2007 (the EFH Corp. Indenture), EFH Corp. issued and sold $2.0 billion aggregate principal amount of 10.875% Senior Notes due November 1, 2017. Interest on the notes (referred to as the EFH Corp. Cash-Pay Notes) is payable in cash semi-annually in arrears on May 1 and November 1 of each year at a fixed rate of 10.875% per annum, and the first interest payment was made on May 1, 2008.

Pursuant to the EFH Corp. Indenture, EFH Corp. also issued and sold $2.5 billion aggregate principal amount of 11.250%/12.000% Senior Toggle Notes due November 1, 2017. The initial interest payment on the notes (referred to as the EFH Corp. Toggle Notes) was paid in cash. For any interest period thereafter until November 1, 2012, EFH Corp. may elect to pay interest on the notes, at EFH Corp.’s option (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFH Corp. Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Interest on the notes is payable semi-annually in arrears on May 1 and November 1 of each year at a fixed rate of 11.250% per annum for cash interest and at a fixed rate of 12.000% per annum for PIK Interest, and the first interest payment was made on May 1, 2008. See “Debt Related Activity in 2008” above for discussion of EFH Corp.’s election to use the PIK option for the May 1, 2009 payment.

The $4.5 billion principal amount of notes issued under the EFH Corp. Indenture (the EFH Corp. Cash-Pay Notes and the EFH Corp. Toggle Notes) are collectively referred to herein as the EFH Corp. Notes.

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The EFH Corp. Notes are fully and unconditionally guaranteed by EFC Holdings and Intermediate Holding, 100% owned subsidiaries of EFH Corp. (the EFH Corp. Guarantors). The EFH Corp. Notes are EFH Corp.’s senior unsecured debt and rank senior in right of payment to any existing and future subordinated indebtedness of EFH Corp., equally in right of payment with all of EFH Corp.’s existing and future senior unsecured indebtedness and structurally subordinated in right of payment to all existing and future indebtedness, preferred stock and other liabilities of EFH Corp.’s non-guarantor subsidiaries, including trade payables (other than indebtedness and liabilities owed to EFH Corp. or the EFH Corp. Guarantors). The EFH Corp. Notes will rank effectively junior in right of payment to all future secured indebtedness of EFH Corp. to the extent of the assets securing that indebtedness.

The guarantees are joint and several guarantees of the EFH Corp. Notes, are the EFH Corp. Guarantors’ unsecured senior obligations and rank equal in right of payment with all existing and future senior unsecured indebtedness of the relevant EFH Corp. Guarantor and senior in right of payment to any existing or future subordinated indebtedness of the relevant EFH Corp. Guarantor. The guarantees of the EFH Corp. Notes will be structurally junior to all indebtedness and other liabilities of the relevant EFH Corp. Guarantor’s subsidiaries that are not guarantors.

The EFH Corp. Indenture contains a number of covenants that, among other things, restrict, subject to certain exceptions, EFH Corp.’s and its restricted subsidiaries’ ability to:

• make restricted payments;

• incur debt and issue preferred stock;

• create liens;

• enter into mergers or consolidations;

• sell or otherwise dispose of certain assets;

• permit dividend and other payment restrictions on restricted subsidiaries, and

• engage in certain transactions with affiliates.

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

EFH Corp. may redeem the EFH Corp. Notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. In addition, before November 1, 2010, EFH Corp. may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the EFH Corp. Notes from time to time at a redemption price of 110.875% of the aggregate principal amount of the EFH Corp. Cash Pay Notes, plus accrued and unpaid interest, if any, or 111.250% of the aggregate principal amount of the EFH Corp. Toggle Notes, plus accrued and unpaid interest, if any. EFH Corp. may also redeem the EFH Corp. 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 a “make-whole” premium. Upon the occurrence of a change in control, EFH Corp. must offer to repurchase the EFH Corp. Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

The EFH Corp. Notes were issued in a private placement with registration rights. Notes having substantially identical terms as the EFH Corp. Notes were registered with the SEC by EFH Corp. in December 2008 as part of an offer to exchange freely tradable exchange notes for the EFH Corp. Notes. The exchange offer was completed in January 2009. Because the exchange offer was not completed within 360 days after the issue date of the EFH Corp. Notes (an EFH Corp. Registration Default), the annual interest rate on the EFH Corp. Notes increased for the period during which the EFH Corp. Registration Default continued (October 26, 2008 to January 30, 2009), resulting in incremental interest of $3.2 million.

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Intercreditor Agreement — In October 2007, in connection with the Merger, TCEH entered into an Intercreditor Agreement (the Intercreditor Agreement) with Citibank, N.A. and five secured commodity hedge counterparties (the Secured Commodity Hedge Counterparties). 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.

TCEH Interest Rate Swap Transactions— In 2007, subsequent to the Merger, TCEH entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $15.05 billion of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.3% and 8.3% on debt maturing from 2009 to 2014. The interest rate swaps were being accounted for as cash flow hedges related to variable interest rate cash flows until August 29, 2008, at which time these swaps were dedesignated as cash flow hedges as a result of the intent to change the variable interest rate terms of the hedged debt (from three-month LIBOR to one-month LIBOR) in connection with the planned execution of interest rate basis swaps (discussed immediately below) to further reduce the fixed borrowing costs. Based on the fair value of the positions, the cumulative unrealized mark-to-market net losses related to these interest rate swaps totaled $431 million (pre-tax) at the dedesignation date and was recorded in accumulated other comprehensive income. This balance will be reclassified into net income as interest on the hedged debt is reflected in net income. No ineffectiveness gains or losses were recorded.

In September 2008, TCEH entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of an additional $1.5 billion of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.3% and 7.6% on debt maturing from 2013 to 2014.

In October 2008, TCEH entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of an additional $1.0 billion of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.5% and 7.6% on debt maturing in 2014.

In May 2008, TCEH entered into an interest rate swap transaction pursuant to which semiannual payment (settled quarterly) of the floating interest rates at LIBOR on an aggregate of $2.095 billion of senior secured term loans of TCEH were exchanged for floating interest rates at LIBOR plus 0.21% receivable monthly.

In September 2008, TCEH entered into interest rate basis swap transactions pursuant to which quarterly payment of the floating interest rates at LIBOR on an aggregate of $7.95 billion of senior secured term loans of TCEH were exchanged for floating interest rates of LIBOR plus spreads ranging from 0.076% to 0.145% receivable monthly.

In November 2008, TCEH entered into interest rate basis swap transactions pursuant to which quarterly payment of the floating interest rates at LIBOR on an aggregate of $3.0 billion of senior secured term loans of TCEH were exchanged for floating interest rates of LIBOR plus spreads ranging from 0.21% to 0.292%, receivable monthly.

The interest rate swap counterparties are secured proportionally with the lenders under the TCEH Senior Secured Facilities. Subsequent to the dedesignation in August 2008 discussed above, changes in the fair value of the swaps discussed in the above paragraphs are being reported in the income statement in interest expense and related charges, and such unrealized mark-to-market net losses totaled $1.477 billion in 2008.

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Oncor Revolving Credit Facility— At December 31, 2008, Oncor had a $2.0 billion credit facility to be used for working capital and general corporate purposes, including issuances of commercial paper and letters of credit. Oncor may request increases in the commitments under the facility in any amount up to $500 million, subject to the satisfaction of certain conditions. This facility is a revolving credit facility, which means that amounts borrowed under the facility, once repaid, can be reborrowed by Oncor from time to time until October 10, 2013. In May 2008, Oncor secured this credit facility with a first priority lien on certain of its transmission and distribution assets. Oncor also secured all of its existing long-term debt securities (excluding the transition bonds) with the same lien in accordance with the terms of those securities. The lien contains customary provisions allowing Oncor to use the assets in its business, as well as to replace and/or release collateral as long as the market value of the aggregate collateral is at least 115% of the aggregate secured debt. The lien may be terminated at Oncor’s option upon the termination of Oncor’s credit facility.

Borrowings under this credit facility totaled $337 million and $1.280 billion at December 31, 2008 and 2007, respectively. The decrease in borrowings reflects the use of the majority of the proceeds from Oncor’s issuance of $1.5 billion of senior secured notes (discussed below) to repay borrowings under the revolving credit facility, partially offset by funding of ongoing capital investments, including the acquisition of broadband over powerline based “Smart Grid” network assets.

Borrowings under this credit facility bear interest at per annum rates equal to, at Oncor’s option, (i) adjusted LIBOR plus a spread of 0.275% to 0.800% (depending on the rating assigned to Oncor’s senior secured debt) or (ii) a base rate (the higher of (1) the prime rate of JPMorgan Chase Bank, N.A. and (2) the federal funds effective rate plus 0.50%). Under option (i) and based on Oncor’s current ratings, its LIBOR-based borrowings, which apply to all outstanding borrowings at December 31, 2008, bear interest at LIBOR plus 0.425%.

A facility fee is payable at a rate per annum equal to 0.100% to 0.200% (depending on the rating assigned to Oncor’s senior secured debt) of the commitments under the facility. Based on Oncor’s current ratings, its facility fee is 0.150%. A utilization fee is payable on the average daily amount of borrowings in excess of 50% of the commitments under the facility at a rate per annum equal to 0.125% per annum.

The credit facility contains customary covenants for facilities of this type, restricting, subject to certain exceptions, Oncor and its subsidiary from, among other things:

• incurring additional liens;

• entering into mergers and consolidations;

• selling certain assets, and

• making acquisitions and investments in subsidiaries.

In addition, the credit facility requires that Oncor maintain a consolidated senior debt-to-capitalization ratio of no greater than 0.65 to 1.00 and observe certain customary reporting requirements and other affirmative covenants.

The credit facility contains certain customary events of default for facilities of this type, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments under the facility.

Oncor Senior Secured Notes— Pursuant to an indenture dated as of August 1, 2002, in September 2008, Oncor issued and sold senior secured notes with an aggregate principal amount of $1.500 billion consisting of $650 million aggregate principal amount of 5.95% senior secured notes maturing in September 2013, $550 million aggregate principal amount of 6.80% senior secured notes maturing in September 2018 and $300 million aggregate principal amount of 7.50% senior secured notes maturing in September 2038. Oncor used the net proceeds of approximately $1.487 billion from the sale of the Oncor notes to repay most of its borrowings under its credit facility as well as for general corporate purposes. The Oncor notes will initially be secured by the first priority lien described above. If the lien is terminated, the notes will cease to be secured obligations of Oncor and will become senior unsecured general obligations of Oncor.

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Interest on these notes is payable in cash semiannually in arrears on March 1 and September 1 of each year, and the first interest payment is due on March 1, 2009. Oncor may redeem the notes, in whole or in part, at any time, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. The notes also contain customary events of default, including failure to pay principal or interest on the notes when due.

The Oncor notes were issued in a private placement and have not been registered under the Securities Act. Oncor has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the Oncor notes as part of an offer to exchange freely tradable exchange notes for the Oncor notes. Oncor has agreed to use commercially reasonable efforts to cause the exchange offer to be completed or, if required, to have one or more shelf registration statements declared effective, within 270 days after the issue date of the Oncor notes. If this obligation is not satisfied (an Oncor Registration Default), the annual interest rate on the Oncor notes will increase by 0.50% per annum over the applicable original interest rate until the earlier of the expiration of the Oncor Registration Default period or the second anniversary of the issue date of the notes. Oncor also agreed to file a registration statement containing a “market making prospectus” and to keep it effective, subject to certain exceptions, for a period of ten years after the issue date of the Oncor notes.

EFH Corp. Long-Term Debt Fair Value Hedges — EFH Corp. has used fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. Interest rate swaps related to $1.850 billion principal amount of debt were dedesignated as fair value hedges in January 2007. These swap positions were unwound by entering into offsetting positions, and both the original swaps and offsetting positions are subsequently being marked-to-market in net income. These swaps qualified for and were designated as fair value hedges in accordance with SFAS 133 (under the “short-cut method” entities are allowed under SFAS 133 to assume no hedge ineffectiveness in a hedging relationship of interest rate risk if certain conditions are met). Fixed-to-variable rate swaps related to $200 million principal amount of debt were dedesignated as fair value hedges at the Merger date and were settled on January 1, 2008 in conjunction with the repayment of the related debt.

Long-Term Debt Fair Value Adjustments Related to Interest Rate Swaps (fixed to variable rate)—

Predecessor:
Long-term debt fair value adjustments related to interest rate swaps at January 1, 2007 — net reduction in debt carrying value (net out-of-the-money value of swaps)	$	(63	)
Fair value adjustments during the period		6
Recognition of net gains on settled fair value hedges (a)		(2	)
Recognition of net losses on dedesignated fair value hedges (b)		7
Successor:
Long-term debt fair value adjustments at October 10, 2007 — net reduction in debt carrying value		(52	)
Purchase accounting adjustment (c)		52
Long-term debt fair value adjustments related to interest rate swaps at December 31, 2007	$	—

(a) Net value of settled in-the-money fixed-to-variable swaps recognized in net income when the hedged transactions are recognized. Amount is pretax.

(b) Net value of dedesignated out-of-the money fixed-to-variable swaps recognized in net income when the hedged transactions are recognized. Amount is pretax.

(c) Reflects the fair-valuing of debt as part of purchase accounting.

Changes in market values of unsettled fair value hedge positions are accounted for as adjustments to the carrying value of related debt amounts, offset by changes in commodity and other derivative contractual asset or liability amounts.

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16. COMMITMENTS AND CONTINGENCIES

Generation Development

Subsidiaries of EFH Corp. have executed EPC agreements for the development of three lignite-fueled generation units in Texas, two units at Oak Grove and one at Sandow, and construction of the units is well underway.

Subsidiaries of EFH Corp. have received the air permits for the Sandow and Oak Grove units. However, the Oak Grove air permit remains the subject of litigation as discussed below under “Litigation Related to Generation Development.”

Construction work-in-process asset balances for the Oak Grove units totaled approximately $2.8 billion as of December 31, 2008, which includes the effects of the fair value adjustments related to purchase accounting and capitalized interest. In the unexpected event the development of the Oak Grove units was cancelled, the cancellation exposure as of December 31, 2008 totaled $3.1 billion, which includes the carrying value of the project and up to approximately $300 million of termination obligations. This estimated exposure amount excludes any potential recovery values for assets acquired to date and for assets already owned prior to executing such agreements that are intended to be utilized for these projects.

Contractual Commitments

At December 31, 2008, EFH Corp. 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		Water Rights Contracts
2009	$	263	$	41	$	3	$	153	$	8
2010		54		38		—		91		8
2011		44		37		—		113		8
2012		—		37		—		182		8
2013		—		42		—		120		8
Thereafter		—		22		—		272		45
Total	$	361	$	217	$	3	$	931	$	85

(a) On the basis of EFH Corp.’s current expectations of demand from its electricity customers as compared with its 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.

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Future minimum lease payments under both capital leases and operating leases are as follows:

	Capital Leases		Operating Leases (a)
2009	$	29	$	61
2010		29		60
2011		71		54
2012		14		51
2013		9		49
Thereafter		50		348
Total future minimum lease payments		202	$	623
Less amounts representing interest		43
Present value of future minimum lease payments		159
Less current portion		19
Long-term capital lease obligation	$	140

(a) Includes operating leases with initial or remaining noncancellable lease terms in excess of one year. Excludes TCEH’s future minimum lease payments for combustion turbines owned by a TCEH lease trust of $17 million in each of 2009 through 2013 and $17 million thereafter.

Rent charged to operating cost, fuel cost and SG&A totaled $92 million for the year ended December 31, 2008, $26 million for the period October 11, 2007 through December 31, 2007, $66 million for the period January 1, 2007 through October 10, 2007 and $86 million for the year ended December 31, 2006.

Litigation Related to Generation Development

An administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas to a subsidiary of EFH Corp. was filed in September 2007 in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. The TCEQ has filed the administrative record with the District Court. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. One of the plaintiffs has asked the court to consolidate all these proceedings, and the Attorney General of Texas, on behalf of TCEQ, has filed pleas to the jurisdiction that would, if granted, dismiss all but the administrative appeal. EFH Corp. does not know when the court will rule on these requests. EFH Corp. believes the Oak Grove air permit granted by the TCEQ is protective of the environment and that the application for and the processing of the air permit by the TCEQ was in accordance with law. There can be no assurance that the outcome of these matters would not result in an adverse impact on the Oak Grove project.

In May 2008, the Sierra Club announced that it may sue Oak Grove Management Company LLC for violating federal Clean Air Act provisions regarding hazardous air pollutants. Similarly, in July 2008, the Sierra Club announced that it may sue Luminant, after the expiration of a 60-day waiting period, for violating federal Clean Air Act provisions in connection with its Martin Lake generation facility. In December 2008, Luminant reached a settlement with the Sierra Club regarding its allegations relating to Oak Grove. Pursuant to the settlement, Luminant has filed for a Maximum Achievable Control Technology determination for hazardous air pollutant emissions by the TCEQ and has agreed to offset any emissions above the levels set in that review; in exchange the Sierra Club will not pursue legal action to obstruct construction or commencement of operation of the Oak Grove units. EFH Corp. cannot predict whether the Sierra Club will actually file suit relating to Martin Lake or the outcome of any such proceeding.

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Other Litigation

In September 2005, a lawsuit was filed in the US District Court for the Northern District of Texas, Dallas Division against EFH Corp. (then known as TXU Corp.) and C. John Wilder, EFH Corp.’s former Chief Executive Officer. The plaintiffs’ Amended Complaint asserts claims on behalf of the plaintiffs and a putative class of owners of certain EFH Corp. securities who tendered such securities in connection with a tender offer conducted by EFH Corp. in 2004. The Amended Complaint alleges violations of the provisions of Sections 14(e), 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 thereunder. The allegations relate to a tender offer conducted in September and October 2004 for certain equity-linked securities in which it was expressly disclosed that EFH Corp. management was evaluating whether it should recommend to the board of directors that the board reevaluate EFH Corp.’s dividend policy. After the tender offer was closed, and consistent with the disclosure, management did make a recommendation to the board to reevaluate the dividend policy, and the board elected to increase the quarterly dividend. The plaintiffs contend that such disclosure in connection with the tender offer was inadequate. EFH Corp. maintains that the disclosure provided in connection with the tender offer regarding the evaluation of the dividend policy was complete and accurate at the time the tender offer was initiated as well as when it was closed. A Motion to Dismiss was filed by the defendants, and the District Court entered an order granting the Motion to Dismiss and dismissing this litigation with prejudice in August 2006. The plaintiffs filed a timely notice of appeal, and on appeal, the US Court of Appeals for the Fifth Circuit remanded the dismissal to the District Court in light of the decisions in Tellabs, Inc. v. Makor Issues & Rights, Ltd. On remand, plaintiffs filed a Second Amended Complaint, and defendants filed a Motion to Dismiss. The District Court entered an order granting the Motion to Dismiss and dismissing this litigation with prejudice in April 2008. The plaintiffs filed a timely notice of appeal in May 2008 and the appeal is currently pending before the US Court of Appeals for the Fifth Circuit. Oral argument was held in February 2009, and EFH Corp. is now awaiting a ruling from the US Court of Appeals for the Fifth Circuit. While EFH Corp. is unable to estimate any possible loss or predict the outcome of this litigation, EFH Corp. believes the claims made in this litigation are without merit and, accordingly, intends to vigorously defend the appeal.

In July 2008, Alcoa Inc. filed a lawsuit in Milam County, Texas district court against Luminant Generation Company LLC, Luminant Mining Company LLC, Sandow Power Company LLC, Luminant Energy Company LLC and EFH Corp. The lawsuit makes various claims concerning operation of the Sandow Unit 4 generation facility and the Three Oaks lignite mine and construction of the Sandow 5 unit, including claims for breach of contract, breach of fiduciary duty, fraud and conversion, and requests money damages in an unspecified amount, declaratory judgment, an accounting and rescission. A federal district court in Austin, Texas has ordered Alcoa Inc. to amend its Milam County complaint to remove any references to a federal consent decree relating to Sandow Units 4 and 5. Alcoa Inc. has not yet filed its amended complaint. While EFH Corp. is unable to estimate any possible loss or predict the outcome of this litigation, EFH Corp. believes the claims made in this litigation are without merit and, accordingly, intends to vigorously defend this litigation.

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Regulatory Investigations and Reviews

In June 2008, the EPA issued a request for information to Luminant Energy under 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. EFH Corp. is cooperating with the EPA and is responding in good faith to the EPA’s request. EFH Corp. is unable to predict the outcome of this matter.

Commitment to Fund Demand Side Management Initiatives

In connection with the Merger, Texas Holdings committed to spend $100 million over the five-year period ending December 31, 2012 on demand side management or other energy efficiency initiatives. This commitment is expected to be funded by EFH Corp. and/or its subsidiaries other than Oncor. This commitment is in addition to $300 million in amounts to be invested by Oncor for similar initiatives. See Note 8 for other provisions of the stipulation, including a similar commitment made by Oncor.

Other Proceedings

In addition to the above, EFH Corp. and its subsidiaries are involved in various other legal and administrative proceedings in the normal course of business the ultimate resolution of which, in the opinion of management, should not have a material effect on its financial position, results of operations or cash flows.

Capital Expenditures

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 one of the provisions of this stipulation, Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions.

Labor Contracts

Certain personnel engaged in TCEH and Oncor activities are represented by labor unions and covered by collective bargaining agreements with varying expiration dates. In January 2008, new one-year labor agreements were reached covering bargaining unit personnel engaged in the natural gas-fueled generation operations and were again renegotiated and completed in January 2009. Also in January 2008, a new two-year agreement was reached covering bargaining unit personnel engaged in lignite mining operations. In June 2008, a new labor agreement effective until October 2010 was reached covering bargaining unit personnel engaged in the Sandow lignite-fueled generation operations. In July 2008, a new labor agreement effective until September 2010 was reached covering bargaining unit personnel engaged in the Three Oaks lignite mining operations. In August 2008, a new labor agreement effective until August 2010 was reached covering bargaining unit personnel engaged in nuclear generation. Negotiations are currently underway with respect to the collective bargaining agreements covering bargaining unit personnel engaged in the Big Brown, Martin Lake and Oak Grove lignite-fueled generation operations and the natural gas-fueled generation operations. The current lignite-fueled generation operations contract, which expired November 2008, is in effect until either party gives notice to terminate, which is unlikely absent unforeseen developments. In February 2008, a new three-year contract was ratified covering bargaining unit personnel engaged in Oncor’s operations. In April 2008, a group of approximately 50 Oncor employees elected to be represented by a labor union. EFH Corp. expects that any changes in collective bargaining agreements will not have a material effect on EFH Corp.’s financial position, results of operations or cash flows; however, EFH Corp. is unable to predict the ultimate outcome of these labor negotiations.

Environmental Contingencies

The federal Clean Air Act, as amended (Clean Air Act) includes provisions which, among other things, place limits on sulfur dioxide and nitrogen oxide emissions produced by electricity generation plants. The capital requirements of EFH Corp. and its subsidiaries have not been significantly affected by the requirements of the Clean Air Act. In addition, all air pollution control provisions of the 1999 Restructuring Legislation have been satisfied.

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EFH Corp. and its subsidiaries must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. EFH Corp. and its subsidiaries believe that they 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.

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 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, and

• the identification of sites requiring clean-up or the filing of other complaints in which EFH Corp. or its subsidiaries may be asserted to be potential responsible parties.

Guarantees

As discussed below, EFH Corp. and its subsidiaries have entered into contracts that contain guarantees to outside parties that could require performance or payment under certain conditions.

Disposed TXU Gas operations —In connection with the TXU Gas transaction in October 2004, EFH Corp. agreed to indemnify Atmos Energy Corporation (Atmos), until October 1, 2014, for up to $500 million for any liability related to assets retained by TXU Gas, including certain inactive gas plant sites not acquired by Atmos, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximum aggregate amount that EFH Corp. may be required to pay is $1.9 billion. To date, EFH Corp. has not been required to make any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.

Residual value guarantees in operating leases — EFH Corp. or a subsidiary is the lessee under various operating leases that guarantee the residual values of the leased assets. At December 31, 2008, the aggregate maximum amount of residual values guaranteed was approximately $63 million with an estimated residual recovery of approximately $69 million. These leased assets consist primarily of mining equipment, rail cars and vehicles. The average life of the residual value guarantees under the lease portfolio is approximately four years.

Indebtedness guarantee —In 1990, EFC Holdings repurchased an electric co-op’s minority ownership interest in the Comanche Peak nuclear generation plant and assumed the co-op’s indebtedness to the US government for the facilities. The indebtedness is included in long-term debt reported in the consolidated balance sheet. EFC Holdings is making principal and interest payments to the co-op in an amount sufficient for the co-op to make payments on its indebtedness. EFC Holdings guaranteed the co-op’s payments, and in the event that the co-op fails to make its payments on the indebtedness, the US government would assume the co-op’s rights under the agreement, and such payments would then be owed directly by EFC Holdings. At December 31, 2008, the balance of the indebtedness was $108 million with maturities of principal and interest extending to December 2021. The indebtedness is secured by a lien on the purchased facilities.

See Note 15 for discussion of guarantees and security for certain EFH Corp. indebtedness.

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Letters of Credit

At December 31, 2008, TCEH had outstanding letters of credit under its credit facilities totaling $767 million as follows:

• $342 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions;

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

• $121 million to support obligations under the lease agreement for an EFH Corp. office building, and

• $96 million for miscellaneous credit support requirements.

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. EFH Corp. intends to maintain insurance against nuclear risks as long as such insurance is available. EFH Corp. 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 adverse effect on EFH Corp.’s financial condition and its results of operations and cash flows.

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, EFH Corp. 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, EFH Corp. has $300 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. EFH Corp.’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 $300 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 $1.1 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. EFH Corp. 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 EFH Corp. 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 $1.75 billion of premature decommissioning coverage also provided by NEIL.

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EFH Corp. 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 a total of $11.7 million for primary property, $14.1 million for excess property and $8.9 million for accidental outage.

Also, under the NEIL policies, if there were multiple terrorism losses occurring within a one-year time frame, NEIL would make available one industry aggregate limit of $3.2 billion plus any amounts it recovers from other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply.

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17. SHAREHOLDERS’ EQUITY

Successor

Equity Contributions and Repurchases— In connection with the Merger, Texas Holdings made an aggregate cash equity contribution of approximately $8.3 billion to EFH Corp. in exchange for EFH Corp. issuing approximately 1.658 billion shares of its common stock to Texas Holdings. In the year ended December 31, 2008 and the period from October 11, 2007 to December 31, 2007, EFH Corp. issued an aggregate of approximately 5.5 million and 2.0 million shares of its common stock, respectively, to, or for the benefit of, certain of its officers, directors and employees for an aggregate consideration of approximately $27.4 million and $9.8 million, respectively. The 2008 amounts include shares previously subscribed. In the year ended December 31, 2008, EFH Corp. repurchased 0.8 million shares of its common stock from employees primarily upon termination of employment or amendment of agreements, for an aggregate consideration of $3.9 million.

Effect of Sale of Minority Interests — Oncor’s sale of minority interests discussed in Note 18 resulted in a $265 million reduction of EFH Corp.’s shareholders’ equity. This amount represents the excess of the carrying value of the interests sold over the proceeds from the transactions, which reflects the fact that Oncor’s carrying value after purchase accounting is based on the Merger value, while the minority interests sale value does not include a control premium.

Dividend Restrictions— The indenture governing the EFH Corp. Senior Cash-Pay and Toggle Notes includes covenants that, among other things and subject to certain exceptions, restrict EFH Corp.’s ability to pay dividends or make other distributions in respect of its capital stock. Accordingly, essentially all of EFH Corp.’s net income is restricted from being used to make distributions on its common stock unless such distributions are expressly permitted under the indenture and/or after such distributions, on a pro forma basis, after giving effect to such payment, the consolidated leverage ratio of EFH Corp. is equal to or less than 7.0 to 1.0. Consolidated leverage ratio is generally defined as the ratio of consolidated total indebtedness (as defined in the indenture) of EFH Corp. to Adjusted EBITDA of EFH Corp., in each case, on a consolidated basis, excluding Oncor Holdings and its subsidiaries. In addition, the TCEH Senior Secured Facilities generally restrict TCEH from making any distribution to any of its parent companies for the ultimate purpose of making a distribution to Texas Holdings 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 TCEH’s Adjusted EBITDA would be equal to or less than 6.5 to 1.0.

Common Stock Registration Rights— The Sponsor Group and certain other investors entered into a registration rights agreement with EFH Corp. upon closing of the Merger. Pursuant to this agreement, in certain instances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.’s common stock owned directly or indirectly by them under the Securities Act. In certain instances, the Sponsor Group and certain other investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.’s common stock under the Securities Act that it may undertake.

See Note 23 for discussion of stock-based compensation plans.

Predecessor

Declaration of Dividend— At its August 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 per share, which was paid October 1, 2007 to shareholders of record on September 7, 2007. At its May 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 per share, which was paid on July 2, 2007 to shareholders of record on June 1, 2007. At its February 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 a share, payable April 2, 2007 to shareholders of record on March 2, 2007.

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Common Stock Repurchase—Under authorization provided by EFH Corp.’s previous board of directors, 19 million shares and 0.2 million shares of common stock were repurchased during the twelve months ended December 31, 2006 and during the period from January 1, 2007 through October 10, 2007 at an average price of $51.77 and $64.80 per share, respectively (including related fees and expenses).

Common Stock Issuance—In May 2006, EFH Corp. settled the purchase contracts associated with its remaining equity-linked debt securities. In connection with the settlement, EFH Corp. issued 5.7 million shares of common stock, resulting in an increase in additional paid-in capital of $180 million.

Thrift Plan— The Thrift Plan is an employee savings plan under which EFH Corp. matched a portion of employees’ contributions of their earnings with a contribution in shares of common stock. Contributions to the Thrift Plan are held by an unconsolidated trust. At October 10, 2007, the Thrift Plan had an obligation of $201 million outstanding in the form of a note payable to EFH Corp. (LESOP note). Proceeds from the issuance of the note, which EFH Corp. purchased from a third-party lender in 1990, were used by the Thrift Plan trustee to purchase EFH Corp.’s common stock on the open market for the purpose of satisfying future matching requirements. These shares (LESOP shares) were held by the Thrift Plan trustee under the leveraged employee stock ownership provision of the Thrift Plan. The note receivable had been classified as a reduction of common stock equity, and the principal and related interest was being amortized as a component of LESOP-related expense.

The Thrift Plan used dividends received on the LESOP shares held and contributions from EFH Corp., if required, to repay interest and principal on the LESOP note; such contributions totaled $14 million for the period from January 1, 2007 through October 10, 2007 and $17 million in 2006.

On the date of the Merger, the Thrift Plan trustee held approximately 5.7 million shares of EFH Corp.’s common stock. These shares were converted to cash at $69.25 per share in connection with the closing of the Merger. The Thrift Plan trustee used the cash proceeds to repay the LESOP note, and then made an additional allocation of the remaining cash proceeds to eligible Thrift Plan participants.

EFC Holdings’ Preferred Stock —In October 2007 prior to the Merger, EFC Holdings issued 4,000 shares of its $4.56 Series preferred stock to EFH Corp. for its membership interests in certain subsidiaries established for the development and construction of new generation facilities.

The table below reflects the changes in the number of Predecessor common stock shares outstanding:

	Period From January 1, 2007 through October 10, 2007		Twelve months ended December 31, 2006
Balance at beginning of period	459,244,523		470,845,978
Issuances under equity-linked debt securities	—		5,683,791
Issuances under stock-based incentive compensation plans (Note 21)	2,771,257		2,200,766
Issued on conversion of convertible senior notes	36,372		—
Repurchases	—		(18,165,403	)
Forfeitures and cancellations under stock-based incentive compensation plans	(900,143	)	(1,320,609	)
Purchased in connection with Merger	(461,152,009	)	—
Balance at end of period	—		459,244,523

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18. MINORITY INTERESTS

On November 5, 2008, Oncor issued and sold additional equity interests to Texas Transmission. Texas Transmission is an entity indirectly owned by a private investment group led by OMERS Administration Corporation, acting through its infrastructure investment entity, Borealis Infrastructure Management Inc., and the Government of Singapore Investment Corporation, acting through its private equity and infrastructure arm, GIC Special Investments Pte Ltd.

Texas Transmission acquired the equity interests for $1.254 billion in cash. At the closing of the sale, Oncor also offered and indirectly sold additional equity interests to certain members of Oncor’s management team. Accordingly, after giving effect to all equity issuances, as of December 31, 2008, EFH Corp. indirectly owns 80.04% of Oncor, Oncor management indirectly owns 0.21% of Oncor and Texas Transmission owns 19.75% of Oncor.

The proceeds (net of closing costs) of $1.253 billion received by Oncor from Texas Transmission and the members of Oncor management upon completion of these transactions were distributed ultimately to EFH Corp. Under the terms of certain financing arrangements of EFH Corp. and TCEH, upon such distribution, under certain circumstances, EFH Corp. (parent entity) is required to repay certain outstanding intercompany loans from TCEH. In November 2008, EFH Corp. repaid the $253 million balance of notes payable to TCEH that related to payments of principal and interest on EFH Corp. (parent entity) debt.

EFH Corp. recorded the $265 million excess of EFH Corp.’s carrying amount of the minority interests sold by Oncor over the net proceeds from the transactions as a reduction to additional paid in capital, consistent with the provisions of SAB Topic 5-H, “Accounting for Sales of Stock by a Subsidiary.”

The minority interests balance of $1.355 billion reported in the December 31, 2008 consolidated balance sheet represented the proportional share of Oncor’s net assets at the date of the transaction less $160 million representing the minority interests’ share of Oncor’s net losses for the period subsequent to the transaction (including the goodwill impairment charge), net of $2 million in cash distributions. See Note 17.

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19. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

The following table provides detail of commodity and other derivative contractual assets and liabilities as presented in the balance sheet:

	Successor
	December 31, 2008
	Commodity contracts		Cash flow hedges and other derivatives			Reclassification (a)			Total
Assets:
Current assets	$	2,385	$	157		$	(8	)	$	2,534
Noncurrent assets		962		—			—			962
Total	$	3,347	$	157		$	(8	)	$	3,496
Liabilities:
Current liabilities	$	2,235	$	681		$	(8	)	$	2,908
Noncurrent liabilities		682		1,413			—			2,095
Total	$	2,917	$	2,094		$	(8	)	$	5,003
Net assets (liabilities)	$	430	$	(1,937	)	$	—		$	(1,507	)

	Successor
	December 31, 2007
	Commodity contracts			Cash flow hedges and other derivatives			Total
Assets:
Current assets	$	1,118		$	11		$	1,129
Noncurrent assets		239			5			244
Total	$	1,357		$	16		$	1,373
Liabilities:
Current liabilities	$	1,042		$	104		$	1,146
Noncurrent liabilities		2,232			221			2,453
Total	$	3,274		$	325		$	3,599
Net assets (liabilities)	$	(1,917	)	$	(309	)	$	(2,226	)

(a) Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current assets and liabilities.

Margin deposit net liabilities of $190 million and net assets of $445 million under master netting arrangements at December 31, 2008 and December 31, 2007, respectively, were not netted with derivative assets and liabilities since EFH Corp. has elected to present the amounts of derivative assets and liabilities on a gross basis in the balance sheet as provided in FSP FIN 39-1. See discussion in Note 1 under “Changes in Accounting Standards.”

This presentation can result in significant volatility in commodity contract assets and liabilities because EFH Corp. enters into positions with the same counterparties that result in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.

175

Commodity Contract Assets and Liabilities

Commodity contract assets and liabilities primarily represent fair values of natural gas and electricity derivative instruments that have not been designated as cash flow hedges or “normal” purchases or sales under SFAS 133. These instruments are marked-to-market, and the associated unrealized gains and losses are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

A multi-year power sales agreement was entered into with Alcoa Inc. in the 2007 Predecessor period. The agreement was determined to have a “day one” out-of-the-money value of $235 million. The agreement was entered into concurrently with the transfer of an air permit from Alcoa Inc. to an EFH Corp. subsidiary as well as other agreements with Alcoa Inc. that provide, among other things, access to real property and a supply of lignite fuel, all of which provides value to EFH Corp. by providing the right and ability to develop, construct and operate a new lignite coal-fueled generation unit at Sandow. In consideration of this right and ability, the initial out-of-the-money value of the sales agreement, as well as a $29 million out-of-the-money value of a related interim power sales agreement entered into in late 2006, were recorded as part of the construction work-in-process asset balance for the Sandow unit. The out-of-the-money values were recorded as commodity contract liabilities. The contracts were revalued applying the principles of SFAS 157 as part of purchase accounting, and subsequent changes in the value of the contracts continue to be marked-to-market in net income.

Successor results include net “day one” losses of $68 million in 2008 and $8 million in the 2007 period, and predecessor results include net "day one" losses of $201 million in the 2007 period, primarily associated with contracts entered into at below market prices. Substantially all of these amounts represent losses associated with related series of transactions involving natural gas financial instruments intended to hedge exposure to future changes in electricity prices. The 2007 predecessor period amount is net of a $30 million “day one” gain associated with a long-term power purchase agreement. The net losses are reported in net gain (loss) from commodity hedging and trading activities, and are included in the results of the Competitive Electric segment.

Other Derivative Assets and Liabilities

Other derivative assets and liabilities primarily represent fair values of interest rate swaps and also include fair values of commodity contracts that have been designated as cash flow hedges.

A significant portion of natural gas derivatives entered into to hedge future changes in electricity prices had previously been designated and accounted for as cash flow hedges. In March 2007, these instruments were dedesignated as cash flow hedges as allowed under SFAS 133, thus becoming subject to mark-to-market accounting in net income as the fair values change. See Note 15 for details of interest rate swaps previously designated as cash flow hedges.

176

A summary of transactions comprising other derivative assets and liabilities follows:

	Successor
	December 31, 2008		December 31, 2007
Current and noncurrent assets:
Interest rate swaps (a)	$	142	$	8
Commodity-related cash flow hedges		15		8
Total	$	157	$	16
Current and noncurrent liabilities:
Interest rate swaps (a)	$	2,086	$	324
Commodity-related cash flow hedges		8		1
Total	$	2,094	$	325
(a)    The 2008 amount includes $1.868 billion in net liabilities related to interest rate hedges on $17.55 billion principal amount of debt and $41 million in net liabilities related to interest rate basis swaps on $13.045 billion principal amount of debt, both entered into after the Merger, and $35 million in net liabilities related to swaps existing at the time of the Merger. As of August 29, 2008, changes in fair value of these swaps are marked-to-market in net income.

Other Cash Flow Hedge Information— EFH Corp. experienced cash flow hedge ineffectiveness of $4 million in net losses in 2008, $111 million in net gains in 2007 (essentially all of which was in the Predecessor period) and $231 million in net gains in 2006. These amounts are pretax and are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

The net effect of recording unrealized mark-to-market gains and losses arising from hedge ineffectiveness (versus recording gains and losses upon settlement) includes the above amounts as well as the effect of reversing unrealized ineffectiveness gains and losses recorded in previous periods to offset realized gains and losses in the current period. Such net unrealized effect totaled $4 million in net losses in the 2008 Successor period, $90 million in net gains in 2007 (essentially all of which was in the Predecessor period) and $239 million in net gains in 2006.

Accumulated other comprehensive income related to cash flow hedges at December 31, 2008 totaled $238 million in net losses (after-tax), substantially all of which relates to interest rate swaps. EFH Corp. expects that $112 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of December 31, 2008 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

177

20. INVESTMENTS

The balance of investments consists of the following:

	Successor
	December 31, 2008		December 31, 2007
Nuclear decommissioning trust	$	385	$	484
Assets related to employee benefit plans, including employee savings programs, net of distributions		210		306
Land		44		44
Note receivable from Capgemini		—		25
Miscellaneous other		6		9
Total investments	$	645	$	868

Nuclear Decommissioning Trust

Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor’s customers as a delivery fee surcharge over the life of the plant and deposited in the trust fund. Net gains and losses on investments in the trust fund are offset by a corresponding adjustment to a regulatory asset/liability. A summary of investments in the fund follows:

	Successor
	December 31, 2008
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities	$	203	$	4	$	(14	)	$	193
Equity securities		181		46		(35	)		192
Total	$	384	$	50	$	(49	)	$	385
	Successor
	December 31, 2007
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities	$	193	$	3	$	(1	)	$	195
Equity securities		168		129		(8	)		289
Total	$	361	$	132	$	(9	)	$	484

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

Debt securities held at December 31, 2008 mature as follows: $73 million in one to five years, $33 million in five to ten years and $87 million after ten years.

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. As of December 31, 2008 and 2007, the face amount of these policies totaled $481 million and $540 million, and the net cash surrender values totaled $155 million and $189 million, respectively. Changes in cash surrender value are netted against premiums paid. Other investment assets held to satisfy deferred compensation liabilities are recorded at fair value.

178

21. NOTICE OF TERMINATION OF OUTSOURCING ARRANGEMENTS

In connection with the closing of the Merger, EFH Corp., TCEH and Oncor commenced a review, under the change of control provision, of certain outsourcing arrangements with Capgemini Energy LP (Capgemini), Capgemini America, Inc. and Capgemini North America, Inc. (collectively, CgE). During the fourth quarter of 2008, EFH Corp. and TCEH executed a Separation Agreement with CgE. Simultaneous with the execution of that Separation Agreement, Oncor entered into a substantially similar Separation Agreement with CgE. The Separation Agreements principally provide for (i) notice of termination of each of the Master Framework Agreements, dated as of May 17, 2004, as each has been amended, between Capgemini and each of TCEH and Oncor and the related service agreements under each of the Master Framework Agreements and (ii) termination of the joint venture arrangements between EFH Corp. (and its applicable subsidiaries) and CgE. Under the Master Framework Agreements and related services agreements, Capgemini provides to EFH Corp. and its subsidiaries outsourced support services, including information technology, customer care and billing, human resources, procurement and certain finance and accounting activities.

Each Separation Agreement acts as a notice of termination under the applicable Master Framework Agreement and the related services agreements. As a result of the “change of control” of EFH Corp. that occurred as a result of the Merger, each of TCEH and Oncor had the contractual right to terminate, without penalty, its Master Framework Agreement. Each of TCEH and Oncor has elected to exercise such right. Consistent with the Master Framework Agreements, to provide for an orderly transition of the services, the Separation Agreements require that Capgemini provide termination assistance services until the services are transitioned back to EFH Corp. and/or to another service provider. The Separation Agreements provide that the services be transitioned by December 31, 2010 (June 30, 2011, in the case of the information technology services). Each Master Framework Agreement will actually terminate when these termination assistance services are completed. EFH Corp. (or its applicable subsidiary) previously provided a termination notice to Capgemini in respect of human resources services and customer care and revenue management services for TXU Energy.

The Separation Agreements provide for the termination of the joint venture arrangement between EFH Corp. (and its applicable subsidiaries) and CgE. As a result, during the fourth quarter of 2008:

• the 2.9% limited partnership interest in Capgemini owned by a subsidiary of EFH Corp. was redeemed in exchange for the termination of the license that was granted by a subsidiary of EFH Corp. to Capgemini at the time the Master Framework Agreements were executed in order for Capgemini to use certain information technology assets primarily consisting of capitalized software to provide services to EFH Corp. and third parties;

• EFH Corp. received approximately $70 million in exchange for the termination of a purchase option agreement pursuant to which subsidiaries of EFH Corp. had the right to “put” to Capgemini (and Capgemini had the right to “call” from a subsidiary of EFH Corp.) EFH Corp.’s 2.9% limited partnership interest in Capgemini and the licensed assets upon the expiration of the Master Framework Agreements in 2014 or, in some circumstances, earlier, and

• Capgemini repaid $25 million (plus accrued interest) representing all amounts owed by Capgemini under the working capital loan provided by EFH Corp. in July 2004.

Under the Separation Agreements, the parties also entered into a mutual release of all claims under the Master Framework Agreements and related services agreements and the joint venture agreements, subject to certain defined exceptions, resulting in EFH Corp. receiving $10 million in cash settlement.

The carrying value of the partnership interest was $2.9 million, and the carrying value of the purchase option was $177 million prior to the application of purchase accounting (recorded as a noncurrent asset). The effects of the termination of the outsourcing arrangements, including an accrual of $66 million for incremental costs to exit and transition the services, were included in the final purchase price allocation (see Note 2).

179

22. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFIT (OPEB) Plans

EFH Corp. is the plan sponsor of the EFH Retirement Plan (Retirement Plan), which provides benefits to eligible employees of consolidated subsidiaries (participating employers). The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code) and is subject to the provisions of ERISA. Employees are eligible to participate in the Retirement Plan upon their completion of one year of service and the attainment of age 21. 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.

All eligible employees hired after January 1, 2001 participate under the Cash Balance Formula. Certain employees who, prior to January 1, 2002, participated under the Traditional Retirement Plan Formula, continue their participation under that formula. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. Effective October 1, 2007, all new employees, with the exception of employees hired by Oncor, are not eligible to participate in the Retirement Plan. New hires at Oncor are eligible to participate in the Cash Balance Formula of the Retirement Plan. It is EFH Corp.’s policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations.

EFH Corp. also has 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.

EFH Corp. offers health care and life insurance benefits 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.

Regulatory Recovery of Pension and OPEB Costs

In June 2005, an amendment to PURA relating to pension and OPEB costs was enacted by the Legislature of the State of Texas. This amendment provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, which in addition to Oncor’s own employees consists largely of active and retired personnel engaged in TCEH’s activities, related to service of those additional personnel prior to the deregulation and disaggregation of EFH Corp.’s businesses effective January 1, 2002. The amendment additionally authorizes Oncor to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Amounts deferred are ultimately subject to regulatory approval. Amounts recorded as a regulatory asset totaled $15 million and $20 million in 2008 and 2007, respectively.

Pension and OPEB Costs Recognized as Expense

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Pension costs under SFAS 87	$	21		$	(1	)	$	34		$	66
OPEB costs under SFAS 106		58			11			49			81
Total benefit costs		79			10			83			147
Less amounts deferred principally as a regulatory asset or property		(42	)		(8	)		(43	)		(84	)
Net amounts recognized as expense	$	37		$	2		$	40		$	63

180

Consistent with SFAS 87, EFH Corp. uses the calculated value method to determine the market-related value of the assets held in its 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.

Detailed Information Regarding Pension Benefits

The following information is based on December 31, 2008 and 2007, October 10, 2007 and December 31, 2006 measurement dates:

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Assumptions Used to Determine Net Periodic Pension Cost:
Discount rate		6.55	%		6.45	%		5.90	%		5.75	%
Expected return on plan assets		8.25	%		8.75	%		8.75	%		8.75	%
Rate of compensation increase		3.70	%		3.44	%		3.44	%		3.32	%
Components of Net Pension Cost:
Service cost	$	36		$	10		$	30		$	42
Interest cost		148			36			107			136
Expected return on assets		(165	)		(47	)		(119	)		(147	)
Amortization of prior service cost		1			—			1			3
Amortization of net loss		1			—			15			32
Recognized curtailment loss		—			—			—			—
Net periodic pension cost	$	21		$	(1	)	$	34		$	66
Other Changes in Plan Assets and Benefit ObligationsRecognized in Other Comprehensive Income:
Net loss (gain)	$	204		$	20		$	(52	)
Transition obligation (asset)		—			—			—
Prior service cost (credit)		—			—			—
Amortization of net loss (gain)		—			—			(3	)
Amortization of transition obligation (asset)		—			—			—
Amortization of prior service cost		—			—			(1	)
Reclassification to regulatory asset		(6	)
Purchase accounting adjustment		(10	)		—			49
Total recognized in other comprehensive income	$	188		$	20		$	(7	)
Total recognized in net periodic benefit cost and other comprehensive income	$	209		$	19		$	27

	Successor				Predecessor
	Year Ended December 31, 2008		Period from October 11, 2007 through December 31, 2007		Period from January 1, 2007 through October 10, 2007		Year Ended December 31, 2006
Assumptions Used to Determine Benefit Obligations:
Discount rate	6.90	%	6.55	%	6.45	%	5.90	%
Rate of compensation increase	3.75	%	3.70	%	3.44	%	3.44	%

181

	Successor
	Year Ended December 31, 2008			Year Ended December 31, 2007
Change in Pension Obligation:
Projected benefit obligation at beginning of year	$	2,335		$	2,457
Service cost		36			40
Interest cost		148			143
Plan amendments		—			—
Actuarial (gain) loss		(58	)		(184	)
Benefits paid		(124	)		(121	)
Settlements		—			—
Projected benefit obligation at end of year	$	2,337		$	2,335
Accumulated benefit obligation at end of year	$	2,203		$	2,219
Change in Plan Assets:
Fair value of assets at beginning of year	$	2,108		$	2,090
Actual return (loss) on assets		(412	)		136
Employer contributions		164			4
Benefits paid		(124	)		(122	)
Settlements		—			—
Fair value of assets at end of year	$	1,736		$	2,108
Funded Status:
Projected pension benefit obligation	$	(2,337	)	$	(2,335	)
Fair value of assets		1,736			2,108
Funded status at end of year	$	(601	)	$	(227	)
	Successor
	Year Ended December 31, 2008			Year Ended December 31, 2007
Amounts Recognized in the Balance Sheet Consist of:
Other noncurrent assets (a)	$	10		$	9
Other current liabilities		(4	)		(4	)
Other noncurrent liabilities		(607	)		(232	)
Net liability recognized	$	(601	)	$	(227	)
Amounts Recognized in Accumulated Other Comprehensive Income Income under SFAS 158 Consist of:
Net loss	$	208		$	20
Prior service cost		—			—
Net amount recognized	$	208		$	20
Amounts Recognized as Regulatory Assets under SFAS 158Consist of:
Net loss	$	387		$	65
Prior service cost		1			2
Net amount recognized	$	388		$	67

(a) Amounts represent overfunded plans.

182

The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated benefit obligation (ABO) in excess of the fair value of plan assets.

	Successor
	December 31, 2008		December 31, 2007
Pension Plans with PBO and ABO in Excess Of Plan Assets:
Projected benefit obligations	$	2,332	$	2,330
Accumulated benefit obligation		2,199		2,214
Plan assets		1,721		2,094

Asset Allocations

The weighted-average asset allocations of pension plans by asset category are as follows:

	Successor
Asset Type	Allocation of Plan Assets 2008		Allocation of Plan Assets 2007		Target Allocation Ranges	Expected Long-Term Returns
US equities	31.7	%	42.1	%	30%-65%	9.7	%
International equities	12.7	%	20.0	%	5%-20%	10.5	%
Fixed income	54.0	%	36.1	%	15%-70%	6.8	%
Real estate	1.6	%	1.8	%	0%-10%	8.0	%
	100.0	%	100.0	%		8.25	%

183

Detailed Information Regarding Postretirement Benefits Other Than Pensions

The following OPEB information is based on December 31, 2008 and 2007, October 10, 2007 and December 31, 2006 measurement dates:

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate		6.55	%		6.45	%		5.90	%		5.75	%
Expected return on plan assets		7.90	%		8.67	%		8.67	%		8.67	%
Components of Net Postretirement Benefit Cost:
Service cost	$	10		$	3		$	9		$	13
Interest cost		59			14			41			60
Expected return on assets		(20	)		(6	)		(15	)		(21	)
Amortization of net transition obligation		1			—			1			1
Amortization of prior service cost/(credit)		(1	)		—			(2	)		(3	)
Amortization of net loss		9			—			15			31
Net periodic OPEB cost	$	58		$	11		$	49		$	81
Other Changes in Plan Assets and Benefit ObligationsRecognized in Other Comprehensive Income:
Net loss (gain)	$	1		$	36		$	(16	)
Transition obligation (asset)		—			—			—
Prior service cost (credit)		—			—			—
Amortization of net loss (gain)		—			—			—
Amortization of transition obligation (asset)		—			—			—
Amortization of prior service cost		—			—			1
Reclassification to regulatory asset		(28	)
Purchase accounting adjustment		(1	)		—			13
Total recognized in other comprehensive income	$	(28	)	$	36		$	(2	)
Total recognized in net periodic benefit cost and other comprehensive income	$	30		$	47		$	47

	Successor				Predecessor
	Year Ended December 31, 2008		Period from October 11, 2007 through December 31, 2007		Period from January 1, 2007 through October 10, 2007		Year Ended December 31, 2006
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate	6.85	%	6.55	%	6.45	%	5.90	%

184

	Successor
	Year Ended December 31, 2008			Year Ended December 31, 2007
Change in Postretirement Benefit Obligation:
Benefit obligation at beginning of year	$	928		$	948
Service cost		10			12
Interest cost		59			55
Participant contributions		16			17
Medicare Part D reimbursement		4			4
Actuarial (gain)/loss		(35	)		(46	)
Benefits paid		(63	)		(62	)
Benefit obligation at end of year	$	919		$	928
Change in Plan Assets:
Fair value of assets at beginning of year	$	260		$	251
Actual return (loss) on assets		(54	)		10
Employer contributions		35			40
Participant contributions		16			17
Medicare Part D reimbursement		4			4
Benefits paid		(63	)		(62	)
Fair value of assets at end of year	$	198		$	260
Funded Status:
Benefit obligation	$	(919	)	$	(928	)
Fair value of assets		198			260
Funded status at end of year	$	(721	)	$	(668	)
	Successor
	Year Ended December 31, 2008			Year Ended December 31, 2007
Amounts Recognized on the Balance Sheet Consist of:
Other noncurrent liabilities	$	(721	)	$	(668	)
Amounts Recognized in Accumulated Other Comprehensive Income under SFAS 158 Consist of:
Net loss	$	7		$	36
Prior service cost credit		—			—
Net transition obligation		—			—
Net amount recognized	$	7		$	36
Amounts Recognized as Regulatory Assets under SFAS 158 Consist of:
Net loss	$	174		$	115
Prior service cost credit		(8	)		(10	)
Net transition obligation		5			6
Net amount recognized	$	171		$	111

185

The following tables provide information regarding the assumed health care cost trend rates.

	Successor
	December 31, 2008		December 31, 2007
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
Health care cost trend rate assumed for next year	8.64	%	7.95	%
Rate to which the cost trend is expected to decline (the ultimate trendtrendtrendratete rate) trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2017		2013
Assumed Health Care Cost Trend Rates-Medicare Eligible:
Health care cost trend rate assumed for next year	8.32	%	8.55	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2017		2013

	1-Percentage Point Increase		1-Percentage Point Decrease
Sensitivity Analysis of Assumed Health Care Cost Trend Rates:
Effect on accumulated postretirement obligation Obligation	$	104	$	(87	)
Effect on postretirement benefits cost		9		(8	)

Asset Allocations –

The weighted average asset allocations of the OPEB plan by asset category are as follows:

	Allocation of Plan Assets
Asset Type	December 31, 2008		December 31, 2007
US equities	43.4	%	52.6	%
International equities	6.7	%	10.3	%
Fixed income	49.0	%	36.2	%
Real estate	0.9	%	0.9	%
	100.0	%	100.0	%

Plan Type	Expected Long-Term Returns
401(h) accounts	8.28	%
Life Insurance VEBA	7.32	%
Union VEBA	7.32	%
Non-Union VEBA	4.00	%
Insurance Continuation Reserve	4.00	%
	7.64	%

Investment Strategy

The investment objective of the Retirement Plan is to provide an adequate long-term return on existing assets and future contributions in order to meet the future benefit obligations of EFH Corp. The EFH Retirement Committee sets asset allocation targets incorporate the timing of future benefits payments and changes in pension legislation, along with asset class risk and return characteristics. The strategy of the OPEB plan is to follow the Retirement Plan strategy, while maintaining sufficient cash and short-term investments to pay near-term benefits and expenses.

186

The fixed income assets are diversified by sector and security and maintain an average quality rating of at least “A” (as determined by a major ratings agency such as Moody’s). The duration of the fixed income assets was lengthened in the fourth quarter of 2008 to match the duration of the liabilities. The equity assets are diversified by size, style and country with a conservative bias toward value securities.

Expected Long-Term Rate of Return on Assets Assumption

EFH Corp. determined the long-term rate of return for each asset class based on historical asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes. The expected return for each asset class was then weighted, based on the target asset allocation, to develop the 8.25% expected long-term rate of return on assets assumption for the portfolio.

Assumed Discount Rate

EFH Corp. selected the assumed discount rate using the Hewitt Top Quartile yield curve based on actual corporate bond yields for AA or better rated bonds at the measurement date as reported by either Moody’s or S&P.

Amortization in 2009

In 2009, EFH Corp. estimates amortization of the net actuarial loss, prior service cost, and transition obligation (asset) for the defined benefit pension plan from accumulated other comprehensive income into net periodic benefit cost will be $7 million, $0.8 million and zero, respectively. EFH Corp. estimates amortization of the net actuarial loss, prior service credit, and transition obligation for the OPEB plan from accumulated other comprehensive income into net periodic benefit cost will be $12 million, $2 million and $1 million, respectively.

Contributions in 2009

Estimated funding for calendar year 2009 totals $81 million for the Retirement Plan and $22 million for the OPEB plan.

Future Benefit Payments

Estimated future benefit payments to beneficiaries are as follows:

	Successor
	2009			2010			2011			2012			2013			2014-18
Pension benefits	$	129		$	135		$	143		$	153		$	161		$	934
OPEB	$	50		$	55		$	58		$	61		$	64		$	365
Medicare Part D subsidies received	$	(6	)	$	(8	)	$	(9	)	$	(9	)	$	(10	)	$	(61	)

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Thrift Plan

Employees of EFH Corp. and its consolidated subsidiaries may participate in a qualified savings plan, the Thrift Plan. This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. The Thrift Plan included an employee stock ownership component until October 10, 2007. 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. Prior to January 1, 2006, employer matching contributions were invested in EFH Corp. common stock. Effective January 1, 2006 through October 10, 2007, employees could reallocate or transfer all or part of their accumulated or future employer matching contributions to any of the plan’s other investment options. As of October 10, 2007, employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options. See Note 17 for additional information related to the Thrift Plan.

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23. STOCK-BASED COMPENSATION PLANS AND PAYMENTS

Successor — EFH Corp. 2007 Stock Incentive Plan

In December 2007, EFH Corp. established the 2007 Stock Incentive Plan for Key Employees of EFH Corp. and its Affiliates (2007 SIP). Incentive awards under the 2007 SIP may be granted to directors and officers and qualified managerial employees of EFH Corp. or its subsidiaries or affiliates in the form of non-qualified stock options, stock appreciation rights, restricted shares, deferred shares, shares of common stock, the opportunity to purchase shares of common stock and other awards that are valued in whole or in part by reference to, or are otherwise based on the fair market value of EFH Corp.’s shares of common stock. The 2007 SIP permits the grant of awards for 72 million shares of common stock, subject to adjustments under applicable laws for certain events, such as a change in control, and no such grants may be issued after December 26, 2017. Shares related to grants that are forfeited, terminated, cancelled, expire unexercised, withheld to satisfy tax withholding obligations, or are repurchased by the Company are available for new grants under the 2007 SIP.

Under the terms of the 2007 SIP, options to purchase 33.1 million and 19.5 million shares of EFH Corp. common stock were issued to certain management employees in 2008 and December 2007, respectively. The options provide the holder the right to purchase EFH Corp. common stock for $5.00 per share. Vested awards must be exercised within 10 years of the grant date. The terms of the options were fixed at grant date.

Stock Options— The stock option awards under the 2007 SIP consist of two types of stock options. One-half of the options awarded 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 awarded vest based upon both continued employment and the achievement of a predetermined level of EFH Corp. EBITDA over time, generally ratably over five years based upon annual EBITDA levels, with provisions for vesting if the annual levels are not achieved but cumulative two- or three-year total EBITDA levels are achieved (“Performance-Based Options”). The Performance-Based Options may also vest in part or in full upon the occurrence of certain specified liquidity events. All options remain exercisable for ten years from the date of grant. Prior to vesting, expenses are recorded if the achievement of the EBITDA levels is probable, and amounts recorded are adjusted or reversed if the probability of achievement of such levels changes. Probability of vesting is evaluated at least each quarter.

The fair value of the Time-Based and Performance-Based 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 is 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 are expected to be outstanding and is calculated using the simplified method prescribed by the SEC Staff Accounting Bulletin No. 107. The simplified method was used since EFH Corp. does 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 is based on the US Treasury security with terms equal to the expected life of the option as of the grant date.

	Successor
	Year Ended December 31, 2008	Period from October 11, 2007 through December 31, 2007		Year Ended December 31, 2008	Period from October 11, 2007 through December 31, 2007
Assumptions	Time-Based Options			Performance-Based Options
Expected volatility	30% – 33%	30	%	30% – 33%	30	%
Expected annual dividend	—	—		—	—
Expected life (in years)	6.0 – 6.5	6.4		5.0 – 7.3	5.4 – 7.4
Risk-free rate	1.51% – 3.50%	3.81	%	1.35% – 3.64%	3.92	%

The weighted average grant-date fair value of the Time-Based Options granted in 2008 and December 2007 was $1.89 and $1.92 per option, respectively. The weighted-average grant-date fair value of the Performance-Based Options granted in 2008 and December 2007 ranged from $1.73 to $2.25 and $1.74 to $2.09, respectively, depending upon the performance period.

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Compensation expense for Time-Based Options is based on the grant-date fair value and recognized over the vesting period as employees perform services. During 2008 and the 2007 Successor period, approximately $11.9 million and less than $100,000, respectively, was recognized as expense for Time-Based Options.

As of December 31, 2008, there was approximately $36.8 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 four years.

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

	Year Ended December 31, 2008						Period from October 11, 2007 through December 31, 2007
Options	Options (millions)		Weighted Average Exercise Price		Aggregate Intrinsic Value (millions)		Options (millions)		Weighted Average Exercise Price		Aggregate Intrinsic Value (millions)
Total outstanding at beginning of period	9.8		$	5.00	$	—	—		$	—	$	—
Granted	16.8			5.00		—	9.8			5.00		—
Exercised	—			—		—	—			—		—
Forfeited	(2.0	)		5.00		—	—			—		—
Total outstanding at end of period (weighted average remaining term of 9 and 10 years)	24.6			5.00		—	9.8			5.00		—
Exercisable at end of period (weighted average remaining term of 9 and 10 years)	(4.7	)		5.00		—	—			—		—
Expected forfeitures	(0.4	)		5.00		—	(0.5	)		5.00		—
Expected to vest at end of period (weighted average remaining term of 9 and 10 years)	19.5			5.00		—	9.3			5.00		—

	Year Ended December 31, 2008				Period from October 11, 2007 through December 31, 2007
Nonvested Options	Options (millions)		Grant-Date Fair Value		Options (millions)	Grant-Date Fair Value
Total nonvested at beginning of period	9.8		$	1.92	—	$	—
Granted	16.8			1.89	9.8		1.92
Vested	(4.7	)		1.80	—		—
Forfeited	(2.0	)		1.92	—		—
Total nonvested at end of period	19.9			2.05	9.8		1.92

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Compensation expense for Performance-Based Options is 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, or if certain liquidity events occur, as discussed above. Expense recognized in 2008 for Performance-Based Options totaled $8.1 million. No amounts were expensed in the 2007 Successor period for Performance-Based Options because the performance period for the first tranche of the options did not begin until January 1, 2008.

As of December 31, 2008, there was approximately $39.4 million of unrecognized compensation expense related to nonvested Performance-Based Options, which EFH Corp. could record as an expense over a remaining weighted-average period of approximately four years, subject to the achievement of financial performance being probable. Pursuant to an amendment to the 2007 SIP Plan terms in February 2009, a total of 4.8 million Performance-Based Options related to the period ended December 31, 2008 were declared vested in recognition that the established 2008 EBITDA target was substantially achieved.

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

	Year Ended December 31, 2008						Period from October 11, 2007 through December 31, 2007
Options	Options (millions)		Weighted Average Exercise Price		Aggregate Intrinsic Value (millions)		Options (millions)		Weighted Average Exercise Price		Aggregate Intrinsic Value (millions)
Outstanding at beginning of period	9.8		$	5.00	$	—	—		$	—	$	—
Granted	16.2			5.00		—	9.8			5.00		—
Exercised	—			—		—	—			—		—
Forfeited	(2.1	)		5.00		—	—			—		—
Total outstanding at end of period (weighted average remaining term of 9 and 10 years)	23.9			5.00		—	9.8			5.00		—
Exercisable at end of period (weighted average remaining term of 9 and 10 years)	—			—		—	—			—		—
Expected forfeitures	(0.5	)		5.00		—	(0.5	)		5.00		—
Expected to vest at end of period (weighted average remaining term of 9 and 10 years)	23.4			5.00		—	9.3			5.00		—

	Year Ended December 31, 2008				Period from October 11, 2007 through December 31, 2007
Nonvested Options	Options (millions)		Grant-Date Fair Value		Options (millions)	Grant-Date Fair Value
Total nonvested at beginning of period	9.8		$	1.74 – 2.09	—	$	—
Granted	16.2			1.73 – 2.25	9.8		1.74 –2.09
Vested	—			—	—		—
Forfeited	(2.1	)		1.74 – 2.09	—		—
Total nonvested at end of period	23.9			1.73 – 2.21	9.8		1.74 – 2.09

Other Share and Share-Based Awards —In 2008, EFH Corp. granted 2.4 million deferred share awards, each of which represents the right to receive one share of EFH Corp. stock, to certain management employees who agreed to forego share-based awards that vested at the Merger date. The deferred share awards are fully vested and are payable in cash or stock upon the earlier of change of control or separation of service. No expense was recorded in 2008 related to these awards. An additional 1.2 million deferred share awards were granted to certain management employees in 2008, approximately half of which are payable in cash or stock and the balance payable in stock; these awards vest over periods of one to five years, and $2.2 million in expense was recorded in 2008 to recognize the vesting. Deferred share awards that are payable in cash or stock are accounted for as liability awards; therefore, the effects of charges in value of EFH Corp. shares are recognized in earnings.

EFH Corp. granted 1.7 million shares of EFH Corp. stock in 2008, and 1.0 million shares in 2007, to board members and other non-employees. The shares vest over periods of one to two years, and a portion may be settled in cash. Expense recognized in 2008 and 2007 related to these grants totaled $8.2 million and $1 million, respectively.

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Stock Appreciation Rights —In 2008, Oncor established the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan (the SARs Plan) under which certain employees of Oncor and its subsidiaries may be granted stock appreciation rights (SARs) payable in cash, or in some circumstances, Oncor units. Two types of SARs may be granted under the SARs Plan. Time-based SARs (Time SARs) vest solely based upon continued employment ratably on an annual basis on each of the first five anniversaries of the grant date. Performance-based SARs (Performance SARs) vest based upon both continued employment and the achievement of a predetermined level of Oncor EBITDA over time, generally ratably over five years based upon annual Oncor EBITDA levels, with provisions for vesting if the annual levels are not achieved but cumulative two- or three-year total Oncor EBITDA levels are achieved. Time and Performance SARs may also vest in part or in full upon the occurrence of certain specified liquidity events and are exercisable only upon the occurrence of certain specified liquidity events. Since the exercisability of the Time and Performance SARs is conditioned upon the occurrence of a liquidity event, compensation expense will not be recorded until it is probable that a liquidity event will occur. Generally, awards under the SARs Plan terminate on the tenth anniversary of the grant, unless the participant’s employment is terminated earlier under certain circumstances.

In February 2009, Oncor implemented a similar plan for primarily non-employee members of Oncor’s board of directors. The terms and conditions are similar to the SARs Plan with the exception that SARs granted to non-employee board members vest in eight equal quarterly installments over a two-year period.

SARs are generally payable in cash based on the fair market value of the SAR on the date of exercise. During 2008, Oncor granted 13.9 million SARs under the SARs Plan, of which 1.4 million Time SARs were vested at December 31, 2008. Pursuant to an amendment to the SARs Plan in February 2009, a total of 1.4 million Performance-SARs related to the period ended December 31, 2008 were declared vested in recognition that the established 2008 EBITDA target was substantially achieved. There were no SARs eligible for exercise at December 31, 2008.

Predecessor

Under its shareholder-approved long-term incentive plans, EFH Corp. provided discretionary awards to qualified management employees payable in its common stock. As presented below, the awards generally vested over a three-year period and the number of shares ultimately earned was based on the performance of the EFH Corp.’s stock over the vesting period.

	Awards Granted in 2007	Awards Granted in 2006
Vesting period	Three years	Three years
Potential share pay-out as a percent of initial number of awards granted	0% to 100% (a)	0% to 175% (a)
Basis for pay-out percentage — actual EFH Corp. three-year share return compared to:	Share returns of companies comprising the S&P 500 Electric Utilities Index	50% of award — threshold EFH Corp. share returns 50% of award — share returns of companies comprising the S&P 500 Electric Utilities Index and S&P 500 Multi-Utilities Index (a)
Award type	Performance units payable in EFH Corp. stock upon vesting	Performance units payable in EFH Corp. stock upon vesting

(a) For a small number of employees under employment agreements, potential share pay-out as a percent of initial number of awards granted was 0% to 200%, and the number of shares distributed was based 100% on EFH Corp.’s total share return over the vesting period compared to the total returns of companies comprising the Standard & Poor’s 500 Electric Utilities Index.

In addition, EFH Corp. established restrictions that limited certain employees’ opportunities to liquidate vested awards. For both restricted stock and performance unit awards, dividends over the vesting periods were converted to equivalent shares of EFH Corp. common stock to be distributed upon vesting.

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The determination of the fair value of stock-based compensation awards at grant date was based on a Monte Carlo simulation. The more significant assumptions used in this valuation process were as follows:

• Expected volatility of the stock price of EFH Corp. and peer group companies — expected volatility was determined based on historical stock price volatilities using daily stock price returns for the three years prior to the grant date.

• The dividend rate for EFH Corp. and peer group companies was based on the observed dividend payments over the twelve months prior to grant date.

• Risk-free rate (three-year US Treasury securities) during the three year vesting period.

• Discount for liquidation restrictions — this factor estimated the discount for lack of marketability of vested awards due to the anticipated time for the approval and issuance of the awards, the black-out period immediately after the grant and additional holding requirements imposed on senior executives. This discount was determined based on an estimation of the cost of a protective put at the award date and is calculated using the Black-Scholes option pricing model using expected volatility assumptions based on historical and implied volatility as discussed above and a risk-free rate of return over the option period.

• For the 2007 grant, change-in-control and no-change-in-control scenarios were considered. The change-in-control scenario was based on three different change-in-control dates each assigned projected probabilities. The change-in-control value was probability weighted with the value assuming no change of control

Assumptions	Period from January 1, 2007 through October 10, 2007	2006
Expected volatility	29% – 30%		29	%
Expected annual dividend	—	$	1.65
Risk-free rate	4.8% – 4.9%		4.83	%
Discount for liquidity restrictions	0% – 4.8%		6.4% – 11.1%

Effective with the 1997 merger of ENSERCH Corporation (subsequently TXU Gas) and EFH Corp., outstanding options for ENSERCH Corporation common stock were exchanged for 1,065,826 options for EFH Corp. common stock (TXU Gas Stock Option Plan). The weighted average exercise price for outstanding options at the beginning of 2006 was $11.95 and the weighted average exercise price for forfeited/expired options was $11.95. All options were granted on or before August 5, 1997 and expired on or before February 16, 2006. No further options may be granted under this plan.

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The following table presents information about Predecessor stock-based compensation plans.

Number of awards:	Performance Unit Awards			Stock Options under TXU Gas Plan
Balance — December 31, 2005		5,285,982		1,520
Granted in 2006		1,052,222		—
Forfeited/expired		(523,946	)	(1,520	)
Vested/exercised		(1,563,918	)	—
Balance — December 31, 2006		4,250,340		—
Granted in period from January 1, 2007 to October 10, 2007		474,000
Forfeited/expired		(41,492	)
Vested/exercised		(4,682,848	)
Balance at Merger closing date		—
Weighted average fair value — Period from January 1, 2007 through October 10, 2007
Outstanding — Beginning of year	$	23.60
Granted	$	67.08
Forfeited	$	36.24
Vested	$	28.30
Outstanding — October 10, 2007	$	—
Weighted average fair value of awards granted in 2006	$	42.35
Period from January 1, 2007 to October 10, 2007	$	67.08

The table above reflects the weighted average fair value of the awards on grant date.

Reported expense related to the awards totaled $27 million ($18 million after-tax) in both the period from January 1, 2007 through October 10, 2007 and year ended December 31, 2006. Such expenses are reported in SG&A expense, except for immaterial amounts capitalized.

The fair value of awards that vested in the period from January 1, 2007 through October 10, 2007 and the year ended 2006 totaled $613 million and $210 million, respectively, based on the vesting date share prices.

Under the terms of the Merger Agreement, all outstanding Performance Unit awards were deemed to be vested at the date of the Merger. See Note 2.

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24. FAIR VALUE MEASUREMENTS

In September 2006, the FASB issued SFAS 157, which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 applies in situations where other accounting pronouncements either permit or require fair value measurements, including purchase accounting and impairment testing of goodwill, indefinite-lived intangible assets and long-lived assets. SFAS 157 does not require any new fair value measurements. However, SFAS 157 supersedes a previous accounting rule that prohibited the recognition of day one gains or losses on derivative instruments unless the fair value of those instruments were derived from an observable market price. Additionally, SFAS 157 requires an entity to take its own credit risk (nonperformance risk) into consideration when measuring the fair value of liabilities. EFH Corp. adopted SFAS 157 effective with the closing of the Merger.

SFAS 157 defines 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. With the adoption of SFAS 157, EFH Corp. uses 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 its assets and liabilities subject to fair value measurement under SFAS 133 and other accounting rules that require such measurement on a recurring basis. EFH Corp. primarily uses the market approach for recurring fair value measurements and uses valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.

EFH Corp. categorizes its assets and liabilities recorded at fair value based upon the following fair value hierarchy established by SFAS 157:

• 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. EFH Corp.’s Level 1 assets and liabilities normally include exchange traded commodity contracts. For example, EFH Corp. has a significant number of derivatives that are NYMEX futures and swaps transacted through clearing brokers for which the pricing is actively quoted.

• Level 2 valuations use inputs other than actively quoted market prices included within Level 1 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. EFH Corp.’s Level 2 assets and liabilities 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, EFH Corp.’s 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. EFH Corp. uses the most meaningful information available from the market combined with its own internally developed valuation methodologies to develop its best estimate of fair value. For example, certain derivative assets or liabilities are derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means.

EFH Corp. utilizes 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.

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In utilizing broker quotes, EFH Corp. attempts to obtain multiple quotes from brokers that are active in the commodity markets in which it participates (and requires 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 that EFH Corp. receives for certain pricing inputs varies depending on the depth of the trading market, each individual broker’s publication policy, recent trading volume shifts and various other factors. Broker quotes received are generally reliable estimates of actively traded markets. In addition, for valuation of interest rate hedges, EFH Corp. uses 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. EFH Corp. believes that development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.

With respect to amounts presented in the following fair value hierarchy table, the fair value measurement of an asset or liability (e.g. a contract) is required under SFAS 157 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.

At December 31, 2008, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Successor
	Level 1		Level 2		Level 3 (a)		Total
Assets:
Commodity-related contracts	$	1,010	$	2,061	$	283	$	3,354
Interest rate swaps		—		142		—		142
Nuclear decommissioning trust (b)		109		276		—		385
Total assets	$	1,119	$	2,479	$	283	$	3,881
Liabilities:
Commodity-related contracts	$	1,288	$	1,274	$	355	$	2,917
Interest rate swaps		—		2,086		—		2,086
Total liabilities	$	1,288	$	3,360	$	355	$	5,003

(a) Level 3 assets and liabilities consist primarily of more complex long-term power purchases and sales agreements, including longer-term wind and other power purchase and sales contracts and certain natural gas positions in the long-term hedging program.

(b) EFH Corp.’s nuclear decommissioning trust investment is included in the Investments line on the balance sheet.

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At December 31, 2007, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Successor
	Level 1		Level 2		Level 3		Reclassification (a)		Total
Assets:
Commodity-related contracts	$	511	$	683	$	148	$	23	$	1,365
Interest rate swaps		—		8		—		—		8
Nuclear decommissioning trust (b)		165		319		—		—		484
Total assets	$	676	$	1,010	$	148	$	23	$	1,857
Liabilities:
Commodity-related contracts	$	559	$	2,372	$	321	$	23	$	3,275
Interest rate swaps		—		324		—		—		324
Total liabilities	$	559	$	2,696	$	321	$	23	$	3,599

(a) 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.

(b) EFH Corp.’s nuclear decommissioning trust investment is included in the Investments line on the balance sheet.

Commodity-related contracts consist primarily of natural gas and electricity derivative instruments entered into for hedging purposes and include physical contracts that have not been designated “normal” purchases or sales under SFAS 133.

Interest rate swaps consist largely of 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 further reduce fixed borrowing costs. See Note 15 for discussion of interest rate swaps.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of EFH Corp.’s nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

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The following table presents the changes in fair value of EFH Corp.’s Level 3 assets and liabilities (all related to commodity contracts) for the year ended December 31, 2008 and the period from October 11, 2007 through December 31, 2007:

	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007
Balance at December 31, 2008 and October 11, 2007, respectively (net liability)	$	(173	)	$	(133	)
Total realized and unrealized gains (losses) (a):
Included in net income (loss)		(12	)		(112	)
Included in other comprehensive income		7			7
Purchases, sales, issuances and settlements (net) (b)		(13	)		14
Net transfers in and/or out of Level 3 (c)		119			51
Balance at end of period (net liability)	$	(72	)	$	(173	)
Net change in unrealized gains (losses) included in net income relating to instruments held at end of period (d)	$	85		$	(70	)

(a) Substantially all changes in values of commodity-related contracts are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

(b) Settlements represent reversals of unrealized mark-to-market valuations of these positions previously recognized in net income. Generally, purchases have no value at inception and subsequent changes in value from these transactions are reflected in unrealized gains and losses. Issuances represent new transactions valued at the assessment date.

(c) Includes transfers due to changes in the observability of significant inputs. Transfers in are assumed to transfer in at the beginning of the quarter and transfers out at the end of the quarter, which is when the assessments were performed. Any changes in value during the period are reported as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities.

(d) Includes unrealized gains and losses related only to the periods in which the instrument was classified as a Level 3 asset or liability.

25. FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of significant nonderivative financial instruments were as follows:

	Successor
	December 31, 2008						December 31, 2007
	Carrying Amount			Fair Value (a)			Carrying Amount			Fair Value (a)
On balance sheet assets (liabilities):
Long-term debt (including current maturities) (b):
TCEH, EFH Corp., and other	$	(35,860	)	$	(24,162	)	$	(35,154	)	$	(34,948	)
Oncor	$	(5,204	)	$	(4,990	)	$	(3,801	)	$	(3,948	)
Total	$	(41,064	)	$	(29,152	)	$	(38,955	)	$	(38,896	)
Off balance sheet assets (liabilities):
Financial guarantees	$	—		$	(3	)	$	—		$	(1	)

(a) Fair value determined in accordance with SFAS 157.

(b) Excludes capital leases.

See Note 19 for discussion of accounting for financial instruments that are derivatives.

198

26. RELATED PARTY TRANSACTIONS

Management Agreement

On October 10, 2007, in connection with the Merger, the Sponsor Group and Lehman Brothers Inc. entered into a management agreement with EFH Corp. (the Management Agreement), pursuant to which affiliates of the Sponsor Group will provide management, consulting, financial and other advisory services to EFH Corp. Pursuant to the Management Agreement, affiliates of the Sponsor Group are entitled to receive an aggregate annual management fee of $35 million, which amount will increase 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of EFH Corp. or in connection with an initial public offering of EFH Corp. or if the parties mutually agree to terminate the Management Agreement. Pursuant to the Management Agreement, affiliates of the Sponsor Group and Lehman Brothers Inc. were paid transaction fees of $300 million for certain services provided in connection with the Merger and related transactions. A portion of these fees were included in the purchase price that was allocated to identifiable assets and liabilities as part of purchase accounting, and the remainder were reported as deferred financing costs. In addition, the Management Agreement provides that the Sponsor Group will be entitled to receive a fee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition, merger combination and change of control transactions, as well as a termination fee based on the net present value of future payment obligations under the Management Agreement in the event of an initial public offering or under certain other circumstances. The fee under the Management Agreement totaled $35 million for the year ended December 31, 2008 and $8 million for the period from October 11, 2007 to December 31, 2007, of which $35 million and $8 million was paid in 2008 and the 2007 period, respectively. The fee is reported as SG&A expense in Corporate and Other operations.

At the closing of the Merger, TCEH entered into the TCEH Senior Secured Facilities and Oncor entered into a revolving credit facility, each 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 GS Capital Partners and Kohlberg Kravis Roberts & Co. L.P. (a member of the Sponsor Group) have from time-to-time engaged in commercial banking and financial advisory transactions with EFH Corp. or its subsidiaries in the normal course of business.

Affiliates of Goldman Sachs & Co. are party to certain commodity and interest rate hedging transactions with EFH Corp. or its subsidiaries in the normal course of business.

From time to time affiliates of the Sponsor Group may acquire debt or debt securities issued by EFH Corp. or its subsidiaries in open market transactions or through loan syndications.

199

27. SEGMENT INFORMATION

EFH Corp.’s operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.

The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, the development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales to residential and business customers, all largely in Texas. These activities are conducted principally by subsidiaries of TCEH. The results of this segment also include equipment salvage and resale activities related to the eight cancelled coal-fueled generation units.

The Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly owned bankruptcy-remote financing subsidiary, and also include certain revenues and costs associated with installation of equipment that will facilitate Oncor's technology initiatives.

Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued operations, general corporate expenses and interest on EFH Corp. and EFC Holdings debt.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. EFH Corp. evaluates performance based on income from continuing operations. EFH Corp. accounts for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.

200

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Operating Revenues
Competitive Electric	$	9,787		$	1,671		$	6,884		$	9,396
Regulated Delivery		2,580			532			1,987			2,449
Corp. and Other		37			11			37			49
Eliminations		(1,040	)		(220	)		(864	)		(1,191	)
Consolidated	$	11,364		$	1,994		$	8,044		$	10,703
Regulated Revenues — Included in Operating Revenues
Competitive Electric	$	—		$	—		$	—		$	—
Regulated Delivery		2,580			532			1,987			2,449
Corp. and Other		—			—			—			—
Eliminations		(1,001	)		(208	)		(824	)		(1,139	)
Consolidated	$	1,579		$	324		$	1,163		$	1,310
Affiliated Revenues — Included in Operating Revenues
Competitive Electric	$	7		$	2		$	5		$	8
Regulated Delivery		1,001			208			824			1,139
Corp. and Other		32			10			35			44
Eliminations		(1,040	)		(220	)		(864	)		(1,191	)
Consolidated	$	—		$	—		$	—		$	—
Depreciation and Amortization
Competitive Electric	$	1,092		$	315		$	253		$	334
Regulated Delivery		492			96			366			476
Corp. and Other		26			4			15			20
Eliminations		—			—			—			—
Consolidated	$	1,610		$	415		$	634		$	830
Equity in Earnings (Losses) of Unconsolidated Subsidiaries (a)
Competitive Electric	$	(10	)	$	(2	)	$	(5	)	$	(10	)
Regulated Delivery		(4	)		(1	)		(2	)		(4	)
Corp. and Other		(5	)		(1	)		(4	)		(19	)
Eliminations		19			4			10			19
Consolidated	$	—		$	—		$	(1	)	$	(14	)
Interest Income
Competitive Electric	$	61		$	10		$	271		$	202
Regulated Delivery		45			12			44			58
Corp. and Other		100			42			106			91
Eliminations		(179	)		(40	)		(365	)		(305	)
Consolidated	$	27		$	24		$	56		$	46
Interest Expense and Related Charges
Competitive Electric	$	4,010		$	609		$	357		$	388
Regulated Delivery		317			70			242			286
Corp. and Other		787			200			437			461
Eliminations		(179	)		(40	)		(365	)		(305	)
Consolidated	$	4,935		$	839		$	671		$	830
Income Tax Expense (Benefit)
Competitive Electric	$	(450	)	$	(656	)	$	306		$	1,239
Regulated Delivery		221			30			160			170
Corp. and Other		(242	)		(47	)		(157	)		(146	)
Eliminations		—			—			—			—
Consolidated	$	(471	)	$	(673	)	$	309		$	1,263

201

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Income (loss) from Continuing Operations
Competitive Electric	$	(8,929	)	$	(1,245	)	$	722		$	2,363
Regulated Delivery		(486	)		63			265			344
Corp. and Other		(423	)		(179	)		(288	)		(242	)
Eliminations		—			—			—			—
Consolidated	$	(9,838	)	$	(1,361	)	$	699		$	2,465
Investment in Equity Investees
Competitive Electric	$	(2	)	$	(1	)				$	—
Regulated Delivery		—			—						—
Corp. and Other		—			—						1
Eliminations		—			—						—
Consolidated	$	(2	)	$	(1	)				$	1
Total assets (b) (c)
Competitive Electric	$	43,061		$	49,297					$	20,289
Regulated Delivery		15,772			15,458						10,709
Corp. and Other		3,526			2,992						1,676
Eliminations		(3,096	)		(2,943	)					(5,458	)
Consolidated	$	59,263		$	64,804					$	27,216
Capital Expenditures
Competitive Electric	$	1,914		$	530		$	1,901		$	1,330
Regulated Delivery		882			153			555			840
Corp. and Other		16			1			7			10
Eliminations		—			—			—			—
Consolidated	$	2,812		$	684		$	2,463		$	2,180

(a) Amounts invested in equity investees were not material in any period presented.

(b) Assets by segment exclude investments in affiliates.

(c) The total assets shown above reflect the change in presentation related to EFH Corp.’s adoption of FSP FIN 39-1 as discussed in Note 1. Such change in presentation resulted in an increase of $1.020 billion and $1.383 billion in EFH Corp.’s total assets and total liabilities as of December 31, 2007 and 2006, respectively, as compared to amounts previously reported in the 2007 Form 10-K.

202

28. SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Operating revenues
Regulated	$	2,580		$	532		$	1,987		$	2,449
Unregulated		9,824			1,682			6,921			9,445
Intercompany sales eliminations — regulated		(1,001	)		(208	)		(824	)		(1,139	)
Intercompany sales eliminations — unregulated		(39	)		(12	)		(40	)		(52	)
Total operating revenues		11,364			1,994			8,044			10,703
Fuel, purchased power and delivery fees — unregulated (a)		(4,595	)		(644	)		(2,381	)		(2,784	)
Net gain (loss) from commodity hedging and trading activities — unregulated		2,184			(1,492	)		(554	)		153
Operating costs — regulated		(828	)		(182	)		(637	)		(770	)
Operating costs — unregulated		(675	)		(124	)		(470	)		(603	)
Depreciation and amortization — regulated		(492	)		(96	)		(366	)		(476	)
Depreciation and amortization — unregulated		(1,118	)		(319	)		(268	)		(354	)
Selling, general and administrative expenses — regulated		(164	)		(45	)		(134	)		(172	)
Selling, general and administrative expenses — unregulated		(793	)		(171	)		(557	)		(647	)
Franchise and revenue-based taxes — regulated		(255	)		(62	)		(198	)		(262	)
Franchise and revenue-based taxes — unregulated		(108	)		(31	)		(84	)		(128	)
Other income		80			14			69			121
Other deductions		(10,161	)		(61	)		(841	)		(269	)
Interest income		27			24			56			46
Interest expense and other charges		(4,935	)		(839	)		(671	)		(830	)
Income (loss) from continuing operations before income taxes and minority interests	$	(10,469	)	$	(2,034	)	$	1,008		$	3,728

(a) Includes unregulated cost of fuel consumed of $1,604 in 2008, $255 million in the period from October 11, 2007 through December 31, 2007, $868 million in the period from January 1, 2007 through October 10, 2007 and $927 million in 2006. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.

The operations of the Competitive Electric segment are included above as unregulated, as the ERCOT wholesale and retail electricity markets are open to competition. However, retail pricing to residential customers in EFH Corp.’s historical service territory was subject to certain price controls until December 31, 2006.

203

Interest Expense and Related Charges

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Interest	$	3,548		$	800		$	732		$	861
Unrealized mark-to-market net loss on interest rate swaps		1,477			—			—			—
Amortization of fair value debt discounts resulting from purchase accounting		75			17			—			—
Amortization of debt issuance cost and discounts		146			81			19			16
Capitalized interest, primarily related to generation facility and regulated utility asset construction		(311	)		(59	)		(80	)		(47	)
Total interest expense and related charges	$	4,935		$	839		$	671		$	830

Restricted Cash

	Successor
	At December 31, 2008				At December 31, 2007
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to TCEH’s Letter of Credit Facility (See Note 15)	$	—	$	1,250	$	—	$	1,250
Amounts related to margin deposits held		4		—		—		—
Pollution control revenue bond funds held by trustee (See Note 15)		—		—		—		29
Amounts related to securitization (transition) bonds		51		17		56		17
Total restricted cash	$	55	$	1,267	$	56	$	1,296

Inventories by Major Category

	Successor
	December 31, 2008		December 31, 2007
Materials and supplies	$	199	$	174
Fuel stock		162		138
Natural gas in storage		65		93
Total inventories	$	426	$	405

204

Property, Plant and Equipment

	Successor
	December 31, 2008		December 31, 2007
Competitive Electric:
Generation and mining	$	16,954	$	17,069
Nuclear fuel (net of accumulated amortization of $235 and $47)		433		451
Other assets		16		22
Regulated Delivery:
Transmission		3,626		3,388
Distribution		8,429		8,036
Other assets		166		106
Corporate and Other		138		124
Total		29,762		29,196
Less accumulated depreciation		5,321		4,076
Net of accumulated depreciation		24,441		25,120
Construction work in progress:
Competitive Electric		4,852		3,358
Regulated Delivery		213		170
Corporate and Other		16		2
Total construction work in progress		5,081		3,530
Property, plant and equipment — net	$	29,522	$	28,650

Assets related to capitalized leases included above totaled $167 million at December 31, 2008 and $161 million at December 31, 2007, net of accumulated depreciation.

205

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 noncurrent liabilities and deferred credits in the balance sheet, during the years ended December 31, 2008 and 2007:

Asset retirement liability at January 1, 2007	$	585
Additions:
Accretion — January 1, 2007 through October 10, 2007		29
Accretion — October 11, 2007 through December 31, 2007		11
Purchase accounting adjustment		176
Reductions:
Mining reclamation cost adjustments		(2	)
Mining reclamation payments — January 1, 2007 through October 10, 2007		(19	)
Mining reclamation payments — October 11, 2007 through December 31, 2007		(7	)
Asset retirement liability at December 31, 2007	$	773
Additions:
Accretion		48
Incremental mining reclamation costs		59
Reductions:
Payments, essentially all mining reclamation		(21	)
Asset retirement liability at December 31, 2008	$	859

206

Regulatory Assets and Liabilities

	Successor
	December 31, 2008		December 31, 2007
Regulatory assets
Generation-related regulatory assets securitized by transition bonds	$	865	$	967
Employee retirement costs		659		265
Self-insurance reserve (primarily storm recovery costs)		214		149
Nuclear decommissioning cost under-recovery		127		—
Securities reacquisition costs		97		105
Recoverable deferred income taxes — net		77		84
Employee severance costs		20		20
Other		12		3
Total regulatory assets		2,071		1,593
Regulatory liabilities
Credit due REPs under PUCT stipulation		—		72
Committed spending for demand-side management initiatives		96		100
Investment tax credit and protected excess deferred taxes		49		55
Over-collection of securitization (transition) bond revenues		28		34
Nuclear decommissioning cost over-recovery		—		13
Other regulatory liabilities		6		14
Total regulatory liabilities		179		288
Net regulatory assets	$	1,892	$	1,305

Regulatory assets that have been reviewed and approved by the PUCT and are not earning a return totaled $1.021 billion and $997 million at December 31, 2008 and 2007, respectively, including the generation-related regulatory assets securitized by transition bonds that have a remaining recovery period of approximately eight years. As part of purchase accounting, the carrying value of the generation-related regulatory assets was reduced by $213 million, and this amount is being accreted to other income over the approximate nine-year recovery period remaining as of the date of the Merger. See Note 8 for discussion of effects on regulatory assets and liabilities of the stipulation approved by the PUCT.

As of December 31, 2008, regulatory assets totaling $913 million have not been reviewed by the PUCT but are deemed by management to be probable of recovery.

207

Other Noncurrent Liabilities and Deferred Credits

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

	Successor
	December 31, 2008		December 31, 2007
Uncertain tax positions (including accrued interest) (Note 10)	$	1,780	$	1,939
Retirement plan and other employee benefits		1,451		1,076
Asset retirement obligations		859		773
Unfavorable purchase and sales contracts		727		751
Liabilities related to subsidiary tax sharing agreement		299		—
Other		89		111
Total other noncurrent liabilities and deferred credits	$	5,205	$	4,650

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: 1) TCEH has made the “normal” purchase or sale election allowed or 2) the contract did not meet the definition of a derivative under SFAS 133. 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 $30 million in 2008 and $5 million in the 2007 Successor period. Favorable purchase and sales contracts are recorded as intangible assets (see Note 3).

The estimated amortization of unfavorable purchase and sales contracts for each of the five succeeding fiscal years from December 31, 2008 is as follows:

	Successor
Year	Amount
2009	$	27
2010		27
2011		27
2012		27
2013		26

Liabilities Related to Subsidiary Tax Sharing Agreement —Amount represents the minority interests’ portion of the previously recorded net deferred tax liabilities of Oncor. Upon the sale of minority interests in Oncor (see Note 18), Oncor became a partnership for US federal income tax purposes, and the temporary differences which gave rise to the deferred taxes will, over time, become taxable to the minority interests. Under a tax sharing agreement among Oncor and its equity holders, Oncor reimburses the equity holders for income taxes as the partnership earnings become taxable to the equity holders. Accordingly, as the temporary differences become taxable, the equity holders will be reimbursed by Oncor. In the unlikely event such amounts are not reimbursed under the tax sharing agreement, it is probable they would be reimbursed to rate payers.

208

Supplemental Cash Flow Information

	Successor						Predecessor
	Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Cash payments (receipts) related to continuing operations:
Interest paid	$	3,495		$	496		$	674		$	870
Capitalized interest		(311	)		(59	)		(80	)		(47	)
Interest paid (net of capitalized interest)		3,184			437			594			823
Income taxes		(204	)		—			271			220
Noncash investing and financing activities:
Below market values of power sales agreements (a)		—			—			264			—
Noncash construction expenditures (b)		183			211			210			228
Promissory note issued in conjunction with acquisition of mining-related assets		—			—			65			—
Capital leases		16			—			52			—
Noncash capital contribution from Texas Holdings		—			23			—			—

(a) Multi-year power sales agreement entered into with Alcoa Inc. and recorded as part of the construction work-in-process asset balance for the Sandow 5 coal-fueled generation unit.

(b) Represents end-of-period accruals.

209

29. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

On October 31, 2007, EFH Corp. refinanced the entire $4.5 billion outstanding under its Senior Unsecured Interim Facility obtained to finance the Merger with $2.0 billion 10.875% Senior Notes Due 2017 and $2.5 billion 11.25%/12.00% Senior Toggle Notes Due 2017 (collectively, the EFH Corp. Notes). The EFH Corp. Notes are unconditionally guaranteed by EFC Holdings and Intermediate Holding, 100% owned subsidiaries of EFH Corp. (collectively, the Guarantors) on an unsecured basis. The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the EFH Corp. Notes. The guarantees 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. All other subsidiaries of EFH Corp., either direct or indirect, do not guarantee the EFH Corp. Notes (collectively, the Non-Guarantors). The EFH Corp. Indenture contains certain restrictions, subject to certain exceptions, on EFH Corp.’s ability to pay dividends or make investments.

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 cash flows of EFH Corp. (the Parent/Issuer), the Guarantors and the Non-Guarantors for the year ended December 31, 2008, the period from October 11, 2007 through December 31, 2007, the period from January 1, 2007 through October 10, 2007 and the year ended December 31, 2006 and the consolidating balance sheets as of December 31, 2008 and 2007 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 5-J, Push Down Basis of Accounting Required in Certain Limited Circumstances, including the effects of the push down of the $4.5 billion EFH Corp. Notes to the Guarantors (see Notes 15 and 16).

EFH Corp. (Parent) received dividends from its consolidated subsidiaries totaling $329 million, $1.461 billion and $1.198 billion for the year ended December 31, 2008, the period from January 1, 2007 through October 10, 2007 and the year ended December 31, 2006, respectively. EFH Corp. also received a distribution of $1.253 billion indirectly from Oncor as discussed in Note 17. No dividends were received during the period from October 11, 2007 through December 31, 2007. See Note 17.

210

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Year Ended December 31, 2008

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	11,364		$	—		$	11,364
Fuel, purchased power costs and delivery fees		—			—			(4,595	)		—			(4,595	)
Net gain from commodity hedging and trading activities		—			—			2,184			—			2,184
Operating costs		—			—			(1,503	)		—			(1,503	)
Depreciation and amortization		—			—			(1,610	)		—			(1,610	)
Selling, general and administrative expenses		(105	)		—			(852	)		—			(957	)
Franchise and revenue-based taxes		—			1			(364	)		—			(363	)
Impairment of goodwill		—			—			(8,860	)		—			(8,860	)
Other income		—			—			80			—			80
Other deductions		(22	)		—			(1,279	)		—			(1,301	)
Interest income		168			7			147			(295	)		27
Interest expense and related charges		(919	)		(537	)		(4,298	)		819			(4,935	)
Income (loss) from continuing operations before income taxes and equity earnings of subsidiaries		(878	)		(529	)		(9,586	)		524			(10,469	)
Income tax (expense) benefit		291			180			176			(176	)		471
Minority interests in net loss of consolidated subsidiaries		—			—			160			—			160
Equity earnings of subsidiaries		(9,251	)		(9,184	)		—			18,435			—
Net loss	$	(9,838	)	$	(9,533	)	$	(9,250	)	$	18,783		$	(9,838	)

211

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Period from October 11, 2007 through December 31, 2007

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	1,994		$	—		$	1,994
Fuel, purchased power costs and delivery fees		—			—			(644	)		—			(644	)
Net loss from commodity hedging and trading activities		—			—			(1,492	)		—			(1,492	)
Operating costs		—			—			(306	)		—			(306	)
Depreciation and amortization		—			—			(416	)		1			(415	)
Selling, general and administrative expenses		(17	)		—			(198	)		(1	)		(216	)
Franchise and revenue-based taxes		(1	)		—			(92	)		—			(93	)
Other income		—			—			14			—			14
Other deductions		(54	)		—			(7	)		—			(61	)
Interest income		54			6			32			(68	)		24
Interest expense and related charges		(234	)		(140	)		(670	)		205			(839	)
Loss from continuing operations before income taxes and equity earnings of subsidiaries		(252	)		(134	)		(1,785	)		137			(2,034	)
Income tax benefit		53			28			637			(45	)		673
Equity earnings of subsidiaries		(1,161	)		(1,142	)		—			2,303			—
Loss from continuing operations		(1,360	)		(1,248	)		(1,148	)		2,395			(1,361	)
Income from discontinued operations, net of tax effect		—			—			1			—			1
Net loss	$	(1,360	)	$	(1,248	)	$	(1,147	)	$	2,395		$	(1,360	)

212

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Period from January 1, 2007 through October 10, 2007

(millions of dollars)

	Predecessor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	8,044		$	—		$	8,044
Fuel, purchased power costs and delivery fees		—			—			(2,381	)		—			(2,381	)
Net loss from commodity hedging and trading activities		—			—			(554	)		—			(554	)
Operating costs		—			—			(1,107	)		—			(1,107	)
Depreciation and amortization		—			—			(634	)		—			(634	)
Selling, general and administrative expenses		(58	)		—			(633	)		—			(691	)
Franchise and revenue-based taxes		—			(1	)		(282	)		1			(282	)
Other income		8			1			60			—			69
Other deductions		(108	)		—			(733	)		—			(841	)
Interest income		133			210			368			(655	)		56
Interest expense and related charges		(566	)		(192	)		(567	)		654			(671	)
Income (loss) from continuing operations before income taxes and equity earnings of subsidiaries		(591	)		18			1,581			—			1,008
Income tax (expense) benefit		235			(2	)		(542	)		—			(309	)
Equity earnings of subsidiaries		1,077			1,554			—			(2,631	)		—
Income from continuing operations		721			1,570			1,039			(2,631	)		699
Income from discontinued operations, net of tax effect		2			—			22			—			24
Net income	$	723		$	1,570		$	1,061		$	(2,631	)	$	723

213

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Year Ended December 31, 2006

(millions of dollars)

	Predecessor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	10,703		$	—		$	10,703
Fuel, purchased power costs and delivery fees		—			—			(2,784	)		—			(2,784	)
Net gain from commodity hedging and trading activities		—			—			153			—			153
Operating costs		—			—			(1,373	)		—			(1,373	)
Depreciation and amortization		—			—			(830	)		—			(830	)
Selling, general and administrative expenses		(70	)		—			(748	)		(1	)		(819	)
Franchise and revenue-based taxes		(1	)		—			(390	)		1			(390	)
Other income		15			—			106			—			121
Other deductions		(7	)		—			(262	)		—			(269	)
Interest income		74			206			367			(601	)		46
Interest expense and related charges		(609	)		(136	)		(703	)		618			(830	)
Income (loss) from continuing operations before income taxes and equity earnings of subsidiaries		(598	)		70			4,239			17			3,728
Income tax (expense) benefit		214			(17	)		(1,460	)		—			(1,263	)
Equity earnings of subsidiaries		2,936			2,792			—			(5,728	)		—
Income from continuing operations		2,552			2,845			2,779			(5,711	)		2,465
Income from discontinued operations, net of tax effect		—			—			87			—			87
Net income	$	2,552		$	2,845		$	2,866		$	(5,711	)	$	2,552

214

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2008

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors			Non-guarantors			Eliminations			Consolidated
Cash flows — operating activities:
Net loss	$	(9,838	)	$	(9,533	)	$	(9,250	)	$	18,783		$	(9,838	)
Adjustments to reconcile loss to cash provided by (used in) operating activities:
Equity in losses of subsidiaries		9,251			9,184			—			(18,435	)		—
Depreciation and amortization		55			23			2,014			(22	)		2,070
Deferred income tax benefit — net		(44	)		1			(434	)		—			(477	)
Impairment of goodwill		—			—			8,860			—			8,860
Impairment of trade name intangible asset		—			—			481			—			481
Impairment of emission allowances intangible assets		—			—			501			—			501
Impairment of natural gas-fueled generation units		—			—			229			—			229
Effect of Parent’s payment of interest on pushed down debt		—			502			—			(502	)		—
Unrealized net gains from mark-to-market valuations of commodity positions		—			—			(2,329	)		—			(2,329	)
Unrealized net losses from mark-to-market valuations of interest rate swaps		—			—			1,477			—			1,477
Other, net		18			—			4			—			22
Changes in operating assets and liabilities:
Margin deposits — net		—			—			595			—			595
Other operating assets and liabilities		307			(1,101	)		(1,316	)		2,024			(86	)
Cash provided by (used in) operating activities		(251	)		(924	)		832			1,848			1,505
Cash flows — financing activities:
Issuances of securities/long-term borrowings:
Long-term debt		—			—			3,185			—			3,185
Common stock		34			—			—			—			34
Retirements/repurchases of securities/long-term borrowings:
Long-term debt		(200	)		(7	)		(960	)		—			(1,167	)
Common stock		(3	)		—			—			—			(3	)
Change in short-term borrowings		—			—			(481	)		—			(481	)
Cash dividends paid		—			(329	)		(329	)		658			—
Change in advances — affiliates		205			7			—			(212	)		—
Other, net		—			—			16			—			16
Cash provided by (used in) financing activities		36			(329	)		1,431			446			1,584
Cash flows — investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(2,978	)		—			(2,978	)
Investments held in money market fund		—			—			(142	)		—			(142	)
Proceeds from sale of minority interests, net of transaction costs		1,253			1,253			1,253			(2,506	)		1,253
Proceeds from sale of environmental allowances and credits		—			—			39			—			39
Purchases of environmental allowances and credits		—			—			(34	)		—			(34	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			1,623			—			1,623
Investments in nuclear decommissioning trust fund securities		—			—			(1,639	)		—			(1,639	)
Change in advances — affiliates		—			—			(212	)		212			—
Other, net		5			—			192			—			197
Cash provided by (used in) investing activities		1,258			1,253			(1,898	)		(2,294	)		(1,681	)
Net change in cash and cash equivalents		1,043			—			365			—			1,408
Cash and cash equivalents — beginning balance		32			—			249			—			281
Cash and cash equivalents — ending balance	$	1,075		$	—		$	614		$	—		$	1,689

215

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Period from October 11, 2007 through December 31, 2007

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows — operating activities:
Net loss	$	(1,360	)	$	(1,248	)	$	(1,147	)	$	2,395		$	(1,360	)
Income from discontinued operations, net of tax		—			—			(1	)		—			(1	)
Loss from continuing operations		(1,360	)		(1,248	)		(1,148	)		2,395			(1,361	)
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Equity in earnings of subsidiaries		1,161			1,142			—			(2,303	)		—
Depreciation and amortization		12			4			556			(4	)		568
Deferred income tax expense (benefit) — net		(357	)		11			(390	)		—			(736	)
Impairments and other asset writedown charges		1			—			1			—			2
Unrealized net losses from mark-to-market valuations of commodity positions		—			—			1,556			—			1,556
Other, net		1			—			15			—			16
Changes in operating assets and liabilities:
Margin deposits — net		—			—			(614	)		—			(614	)
Other		712			(220	)		(285	)		(88	)		119
Cash provided by (used in) operating activities of continuing operations		170			(311	)		(309	)		—			(450	)
Cash flows — financing activities:
Issuance of securities:
Equity financing from Sponsor Group		8,236			—			—			—			8,236
Long-term debt		9,000			—			33,732			—			42,732
Retirements/repurchases of long-term debt		(5,522	)		(4	)		(9,869	)		—			(15,395	)
Change in short-term borrowings		—			—			(722	)		—			(722	)
Change in advances — affiliates		33			—			—			(33	)		—
Contributions to parent		—			(21,000	)		(21,000	)		42,000			—
Other, net		(400	)		1			(587	)		—			(986	)
Cash provided by (used in) financing activities		11,347			(21,003	)		1,554			41,967			33,865
Cash flows — investing activities:
Acquisition of EFH Corp.		(32,694	)		—			—			—			(32,694	)
Contribution from subsidiaries		21,000			21,000			—			(42,000	)		—
Capital expenditures and nuclear fuel		(2	)		—			(705	)		—			(707	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			831			—			831
Investments in nuclear decommissioning trust fund securities		—			—			(835	)		—			(835	)
Proceeds from letter of credit facility deposited with trustee		—			—			(1,250	)		—			(1,250	)
Change in advances — affiliates		—			314			(347	)		33			—
Other, net		(3	)		—			95			—			92
Cash provided by (used in) investing activities		(11,699	)		21,314			(2,211	)		(41,967	)		(34,563	)

216

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows (cont.)

Period from October 11, 2007 through December 31, 2007

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors		Non-Guarantors			Eliminations		Consolidated
Cash flows — discontinued operations:
Operating activities		—			—		(7	)		—		(7	)
Financing activities		—			—		—			—		—
Investing activities		—			—		—			—		—
Cash used in discontinued operations		—			—		(7	)		—		(7	)
Net change in cash and equivalents		(182	)		—		(973	)		—		(1,155	)
Cash and cash equivalents — beginning balance		214			—		1,222			—		1,436
Cash and cash equivalents — ending balance	$	32		$	—	$	249		$	—	$	281

217

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Period from January 1, 2007 through October 10, 2007

(millions of dollars)

	Predecessor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows — operating activities:
Net income	$	723		$	1,570		$	1,061		$	(2,631	)	$	723
Income from discontinued operations, net of tax		(2	)		—			(22	)		—			(24	)
Income from continuing operations		721			1,570			1,039			(2,631	)		699
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Equity in earnings of subsidiaries		(1,077	)		(1,554	)		—			2,631			—
Depreciation and amortization		—			—			684			—			684
Deferred income tax expense (benefit) — net		(67	)		1			(45	)		—			(111	)
Impairments and other asset writedown charges		68			—			646			—			714
Unrealized net losses from mark-to-market valuations of commodity positions		—			—			722			—			722
Other, net		20			(1	)		(5	)		—			14
Changes in operating assets and liabilities:
Margin deposits — net		—			—			(569	)		—			(569	)
Other		1,464			1,452			118			(2,922	)		112
Cash provided by operating activities of continuing operations		1,129			1,468			2,590			(2,922	)		2,265
Cash flows — financing activities:
Issuance of securities:
Long-term debt		—			—			1,800			—			1,800
Common stock		1			—			—			—			1
Retirements/repurchases of securities:
Long-term debt		(1	)		(13	)		(431	)		—			(445	)
Common stock		(13	)		—			—			—			(13	)
Change in short-term borrowings		—			—			949			—			949
Cash dividends paid		(788	)		(1,461	)		(1,461	)		2,922			(788	)
Change in advances — affiliates		50			—			—			(50	)		—
Other, net		(93	)		—			(17	)		—			(110	)
Cash provided by (used in) financing activities		(844	)		(1,474	)		840			2,872			1,394
Cash flows — investing activities:
Capital expenditures and nuclear fuel		(70	)		—			(2,447	)		—			(2,517	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			602			—			602
Investments in nuclear decommissioning trust fund securities		—			—			(614	)		—			(614	)
Change in advances — affiliates		—			6			(56	)		50			—
Other, net		(1	)		—			247			—			246
Cash provided by (used in) investing activities		(71	)		6			(2,268	)		50			(2,283	)

218

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows (cont.)

Period from January 1, 2007 through October 10, 2007

(millions of dollars)

	Predecessor
	Parent/Issuer		Guarantors		Non-Guarantors		Eliminations		Consolidated
Cash flows — discontinued operations:
Operating activities		—		—		35		—		35
Financing activities		—		—		—		—		—
Investing activities		—		—		—		—		—
Cash provided by discontinued operations		—		—		35		—		35
Net change in cash and equivalents		214		—		1,197		—		1,411
Cash and cash equivalents — beginning balance		—		—		25		—		25
Cash and cash equivalents — ending balance	$	214	$	—	$	1,222	$	—	$	1,436

219

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2006

(millions of dollars)

	Predecessor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows — operating activities:
Net income	$	2,552		$	2,845		$	2,866		$	(5,711	)	$	2,552
Income from discontinued operations, net of tax		—			—			(87	)		—			(87	)
Income from continuing operations		2,552			2,845			2,779			(5,711	)		2,465
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Equity in earnings of subsidiaries		(2,936	)		(2,792	)		—			5,728			—
Depreciation and amortization		—			—			893			—			893
Deferred income tax expense (benefit) — net		116			(9	)		649			—			756
Impairments and other asset writedown charges		—			—			204			—			204
Unrealized net gains from mark-to-market valuations of commodity positions		—			—			(272	)		—			(272	)
Other, net		6			—			162			—			168
Changes in operating assets and liabilities:
Margin deposits — net		—			—			564			—			564
Other		482			1,528			892			(2,726	)		176
Cash provided by operating activities of continuing operations		220			1,572			5,871			(2,709	)		4,954
Cash flows — financing activities:
Issuance of securities:
Long-term debt		—			—			243			—			243
Common stock		180			—			—			—			180
Retirements/repurchases of securities:
Long-term debt		(911	)		(6	)		(774	)		—			(1,691	)
Common stock		(960	)		—			—			—			(960	)
Change in short-term borrowings		—			—			694			—			694
Cash dividends paid		(764	)		(1,198	)		(1,484	)		2,682			(764	)
Change in advances — affiliates		1,724			—			981			(2,705	)		—
Other, net		(12	)		—			(22	)		—			(34	)
Cash used in financing activities		(743	)		(1,204	)		(362	)		(23	)		(2,332	)
Cash flows — investing activities:
Capital expenditures and nuclear fuel		(12	)		—			(2,285	)		—			(2,297	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			207			—			207
Investments in nuclear decommissioning trust fund securities		—			—			(223	)		—			(223	)
Change in advances — affiliates		—			(299	)		(2,433	)		2,732			—
Investment in collateral trust		533			—			(533	)		—			—
Other, net		2			(69	)		(284	)		—			(351	)
Cash provided by (used in) investing activities		523			(368	)		(5,551	)		2,732			(2,664	)

220

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows (cont.)

For the Year Ended December 31, 2006

(millions of dollars)

	Predecessor
	Parent/Issuer		Guarantors		Non-Guarantors			Eliminations		Consolidated
Cash flows — discontinued operations:
Operating activities		—		—		30			—		30
Financing activities		—		—		—			—		—
Investing activities		—		—		—			—		—
Cash provided by discontinued operations		—		—		30			—		30
Net change in cash and equivalents		—		—		(12	)		—		(12	)
Cash and cash equivalents — beginning balance		—		—		37			—		37
Cash and cash equivalents — ending balance	$	—	$	—	$	25		$	—	$	25

221

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at December 31, 2008

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	1,075		$	—		$	614	$	—		$	1,689
Investments held in money market fund		—			—			142		—			142
Restricted cash		—			—			55		—			55
Advances to parent		403			7			—		(410	)		—
Trade accounts receivable — net		3			—			1,216		—			1,219
Income taxes receivable		—			—			128		(86	)		42
Accounts receivable from affiliates		—			—			3		(3	)		—
Notes receivable from affiliates		—			—			633		(633	)		—
Inventories		—			—			426		—			426
Commodity and other derivative contractual assets		143			—			2,391		—			2,534
Accumulated deferred income taxes		—			—			80		(36	)		44
Margin deposits related to commodity positions		—			—			439		—			439
Other current assets		6			—			159		—			165
Total current assets		1,630			7			6,286		(1,168	)		6,755
Restricted cash		—			—			1,267		—			1,267
Investments		3,899			2,793			579		(6,626	)		645
Property, plant and equipment — net		—			—			29,522		—			29,522
Notes receivable from affiliates		12			—			2,273		(2,285	)		—
Goodwill		—			—			14,386		—			14,386
Intangible assets — net		—			—			2,993		—			2,993
Regulatory assets — net		—			—			1,892		—			1,892
Commodity and other derivative contractual assets		—			—			962		—			962
Accumulated deferred income taxes		575			6			—		(581	)		—
Unamortized debt issuance costs and other noncurrent assets		130			111			711		(111	)		841
Total assets	$	6,246		$	2,917		$	60,871	$	(10,771	)	$	59,263
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	—		$	—		$	1,237	$	—		$	1,237
Advances from affiliates		—			—			410		(410	)		—
Long-term debt due currently		3			8			374		—			385
Trade accounts payable		8			—			1,135		—			1,143
Accounts payable to affiliates		—			3			—		(3	)		—
Notes payable to affiliates		585			13			35		(633	)		—
Commodity and other derivative contractual liabilities		178			—			2,730		—			2,908
Margin deposits related to commodity positions		—			—			525		—			525
Accumulated deferred income taxes		36			—			—		(36	)		—
Accrued interest		110			87			413		(86	)		524
Other current liabilities		111			—			587		(86	)		612
Total current liabilities		1,031			111			7,446		(1,254	)		7,334
Accumulated deferred income taxes		—			—			6,507		(581	)		5,926
Investment tax credits		—			—			42		—			42
Commodity and other derivative contractual liabilities		—			—			2,095		—			2,095
Notes or other liabilities due affiliates		2,019			—			266		(2,285	)		—
Long-term debt, less amounts due currently		6,340			4,597			34,401		(4,500	)		40,838
Other noncurrent liabilities and deferred credits		388			1			4,817		(1	)		5,205
Total liabilities		9,778			4,709			55,574		(8,621	)		61,440
Minority interests		—			—			1,355		—			1,355
Shareholders’ equity		(3,532	)		(1,792	)		3,942		(2,150	)		(3,532	)
Total liabilities and shareholders’ equity	$	6,246		$	2,917		$	60,871	$	(10,771	)	$	59,263

222

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at December 31, 2007

(millions of dollars)

	Successor
	Parent/ Issuer		Guarantors		Non-guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	32	$	—	$	249	$	—		$	281
Restricted cash		—		—		56		—			56
Advances to parent		378		1		—		(379	)		—
Trade accounts receivable – net		28		—		1,071		—			1,099
Income taxes receivable		—		44		366		(309	)		101
Accounts receivable from affiliates		—		82		29		(111	)		—
Notes receivable from affiliates		—		—		59		(59	)		—
Inventories		—		—		405		—			405
Commodity and other derivative contractual assets		3		—		1,126		—			1,129
Accumulated deferred income taxes		—		1		76		(68	)		9
Margin deposits related to commodity positions		—		—		513		—			513
Other current assets		253		—		123		—			376
Total current assets		694		128		4,073		(926	)		3,969
Restricted cash		—		—		1,296		—			1,296
Investments		15,157		13,860		749		(28,898	)		868
Property, plant and equipment – net		—		—		28,650		—			28,650
Notes receivable from affiliates		12		—		2,308		(2,320	)		—
Goodwill		—		—		22,954		—			22,954
Intangible assets – net		—		—		4,365		—			4,365
Regulatory assets – net		—		—		1,305		—			1,305
Commodity and other derivative contractual assets		—		—		244		—			244
Accumulated deferred income taxes		478		19		—		(497	)		—
Unamortized debt issuance costs and other noncurrent assets		144		132		986		(132	)		1,130
Assets held for sale		—		—		23		—			23
Total assets	$	16,485	$	14,139	$	66,953	$	(32,773	)	$	64,804
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	—	$	—	$	1,718	$	—		$	1,718
Advances from affiliates		—		—		379		(379	)		—
Long-term debt due currently		200		7		306		—			513
Trade accounts payable		6		—		898		—			904
Accounts payable to affiliates		110		—		—		(110	)		—
Notes payable to affiliates		25		—		34		(59	)		—
Commodity and other derivative contractual liabilities		38		—		1,108		—			1,146
Margin deposits related to commodity positions		—		—		5		—			5
Accumulated deferred income taxes		69		—		—		(69	)		—
Accrued interest		114		87		422		(86	)		537
Other current liabilities		556		—		586		(263	)		879
Total current liabilities		1,118		94		5,456		(966	)		5,702
Accumulated deferred income taxes		—		—		7,161		(497	)		6,664
Investment tax credits		—		—		47		—			47
Commodity and other derivative contractual liabilities		—		—		2,453		—			2,453
Notes or other liabilities due affiliates		2,019		—		301		(2,320	)		—
Long-term debt, less amounts due currently		6,288		4,603		32,212		(4,500	)		38,603
Other noncurrent liabilities and deferred credits		375		—		4,275		—			4,650
					��
Total liabilities		9,800		4,697		51,905		(8,283	)		58,119
Shareholders’ equity		6,685		9,442		15,048		(24,490	)		6,685
Total liabilities and shareholders’ equity	$	16,485	$	14,139	$	66,953	$	(32,773	)	$	64,804

223

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 EFH Corp.’s 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, 2008. Based on the evaluation performed, EFH Corp.’s management, including the principal executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective.

There have been no changes in EFH Corp.’s internal controls over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, EFH Corp.’s internal control over financial reporting.

224

ENERGY FUTURE HOLDINGS CORP.

MANAGEMENT’S ANNUAL REPORT ON

INTERNAL CONTROL OVER FINANCIAL REPORTING

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

The management of Energy Future Holdings Corp. performed an evaluation as of December 31, 2008 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, 2008 Energy Future Holdings Corp.’s internal control over financial reporting was effective.

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

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

March 2, 2009

225

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the internal control over financial reporting of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) as of December 31, 2008 (successor) based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. EFH Corp.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on EFH Corp.’s internal control over financial reporting based on our audit.

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

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made 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 the changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, EFH Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

226

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, 2008 (successor) and for the year ended December 31, 2008 (successor) of EFH Corp. and our report dated March 2, 2009 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the completion of the EFH Corp. merger with Texas Future Merger Sub Corp on October 10, 2007 and EFH Corp.’s adoption of the provisions of FASB Staff Position No. FIN 39-1 and reclassification of the results of its commodity hedging and trading activities on a retrospective basis.

/s/ Deloitte & Touche LLP

Dallas, Texas

March 2, 2009

227

Item 9B. OTHER INFORMATION

None.

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Directors

The names of EFH Corp.’s directors and information about them, as furnished by the directors themselves, are set forth below:

Name	Age	Served As Director Since	Business Experience
Arcilia C. Acosta (4)	43	2008	Arcilia C. Acosta has served as a Director of EFH Corp. since May 2008. During the last five years, Ms. Acosta’s principal occupation and employment has been serving as the CEO of CARCON Industries & Construction, L.L.C. (CARCON) and its subsidiaries. She is also the CEO and controlling principal of Southwestern Testing Laboratories, L.L.C., (STL). CARCON’s principal business is commercial, institutional and transportation construction. STL’s principal business is geotechnical engineering, construction materials testing and environmental consulting. Ms. Acosta is a former Chair of the State of Texas Hispanic chambers organization known as the Texas Association of Mexican American Chambers of Commerce (TAMACC). Ms. Acosta serves on the Board of Advisors for Compass Bank and the Board of Governors for the Dallas Foundation.
David Bonderman	66	2007	David Bonderman has served as a Director of EFH Corp. since October 2007. He is a founding partner of TPG Capital, L.P. (TPG). Before forming TPG in 1992, Mr. Bonderman was Chief Operating Officer of the Robert M. Bass Group (now doing business as Keystone Group L.P.) in Fort Worth, Texas. He serves on the boards of the following public companies: CoStar Group, Inc., Gemalto N.V., and RyanAir Holdings PLC, of which he is Chairman.
Donald L. Evans (1)(2)(3)(4)	62	2007	Donald L. Evans has served as a Director of EFH Corp. since October 2007. He has been Non-Executive Chairman of EFH Corp. since October 2007 and was CEO of the Financial Services Forum from 2005 to 2007, after serving as the 34th secretary of the US Department of Commerce. Before serving as Secretary of Commerce, Secretary Evans was the former CEO of Tom Brown, Inc., a large independent energy company. He formerly served as a member and chairman of the Board of Regents of the University of Texas System.

228

Name	Age	Served As Director Since	Business Experience
Thomas D. Ferguson	55	2008	Thomas D. Ferguson has served as a Director of EFH Corp. since December 2008. He is a Managing Director of Goldman, Sachs & Co., having joined the firm in 2003. Mr. Ferguson heads the asset management efforts for the Merchant Bank’s infrastructure investment activity worldwide. He currently serves on the boards of some of Goldman, Sachs & Co.’s largest infrastructure investments including Associated British Ports, the largest port company in the UK; Carrix, one of the largest private container terminal operators in the world; and Red de Carreteras, a major toll road concessionaire in Mexico. Additional responsibilities at the firm include an 18 month stint as the CEO of National Golf/American Golf, one of the leading owner/operators of golf courses in the US for which he now serves as the company’s non-executive Chairman.
Frederick M. Goltz (2)(3)	38	2007	Frederick M. Goltz has served as a Director of EFH Corp. since October 2007. He has been with Kohlberg Kravis Roberts and Co., L.P. (KKR) for 13 years. Mr. Goltz has played a significant role in the development of many of the themes pursued by KKR in the energy space, including those related to integrated utilities, merchant generation, and oil and gas exploration and production. He now heads KKR’s newly created Mezzanine Fund headquartered in San Francisco. He is a director of EFC Holdings, TCEH, and Luminant.
James R. Huffines (1)(3)	58	2007	James R. Huffines has served as a Director of EFH Corp. since October 2007. He is vice chairman of the University of Texas System Board of Regents, after previously serving as Chairman for three and a half years. He also is Chairman, Central and South Texas Region, of PlainsCapital Bank, Senior Executive Vice President of PlainsCapital Corporation, and a director of Hester Capital Mgmt., PlainsCapital Bank, and PlainsCapital Corp. He previously held senior management positions at Hester Capital Management, L.L.C., and Morgan Keegan & Co.
Scott Lebovitz	33	2007	Scott Lebovitz has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He joined Goldman, Sachs & Co. in 1997 and was promoted to Managing Director in 2007. Mr. Lebovitz serves on the boards of both public and private companies including CVR Energy, Inc., Village Voice Media, LLC, EFC Holdings, TCEH, and Luminant.
Jeffrey Liaw (1)	32	2007	Jeffrey Liaw has served as a Director of EFH Corp. since October 2007. He is active in TPG’s energy and industrial investing practice areas. Before joining TPG in 2005, he worked for Bain Capital in its industrials practice since 2001. Mr. Liaw serves on the boards of both public and private companies including Graphic Packaging Corporation and Oncor.

229

Name	Age	Served As Director Since	Business Experience
Marc S. Lipschultz (2)(4)	40	2007	Marc S. Lipschultz has served as a Director of EFH Corp. since October 2007. He joined KKR in 1995. He is the leader of KKR’s Energy and Infrastructure businesses. Currently, he is a director of Accel-KKR Company and Oncor.
Michael MacDougall (2)(3)	38	2007	Michael MacDougall has served as a Director of EFH Corp. since October 2007. He is a partner of TPG. Prior to joining TPG in 2002, Mr. MacDougall was a vice president in the Principal Investment Area of the Merchant Banking Division of Goldman, Sachs & Co., where he focused on private equity and mezzanine investments. Mr. MacDougall serves on the board of directors of both public and private companies including Aleris International, Graphic Packaging Corporation, Kraton Polymers LLC, EFC Holdings, TCEH, and Luminant. Mr. MacDougall also serves as the Chairman of the Board of The Opportunity Network and is a member of the Board of the Dwight School Foundation and Islesboro Affordable Property.
Lyndon L. Olson, Jr. (3)	61	2007	Lyndon L. Olson, Jr. has served as a Director of EFH Corp. since October 2007. He was a Senior Advisor with Citigroup Inc. from 2002 to 2008, after serving as United States Ambassador to Sweden from 1998 to 2001. He previously was affiliated with Citigroup from 1990 to 1998, as President and CEO of Travelers Insurance Holdings and the Associated Madison Companies, predecessor companies. Before joining Citigroup, he had been President of the National Group Corporation and CEO of its National Group Insurance Company. Ambassador Olson also is a former Chairman and a Member of the Texas 173 State Board of Insurance, former President of the National Association of Insurance Commissioners, and a former member of the Texas House of Representatives.
Kenneth Pontarelli (2)(4)	38	2007	Kenneth Pontarelli has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He transferred to the Principal Investment Area in 1999 and was promoted to Managing Director in 2004 and to Partner in 2006. Mr. Pontarelli serves as a director of both public and private companies including CCS, Inc., Cobalt International Energy, L.P., CVR Energy, Inc., Knight Inc., and TXU Energy.

230

Name	Age	Served As Director Since	Business Experience
William K. Reilly	69	2007	William K. Reilly has served as a Director of EFH Corp. since October 2007. He is a Senior Advisor to TPG and a founding partner of Aqua International Partners, an investment group that invests in companies that serve the water and renewable energy sectors. Mr. Reilly previously served as the seventh Administrator of the US Environmental Protection Agency. Mr. Reilly is a director of the following public companies: E.I DuPont de Nemours and Company, Eden Springs, Ltd. of Israel, ConocoPhillips and Royal Caribbean International. Before serving as EPA Administrator, he was President of World Wildlife Fund and President of The Conservation Foundation. He previously served as Executive Director of the Rockefeller Task Force on Land Use and Urban Growth, a senior staff member of the President’s Council on Environmental Quality, and Associate Director of the Urban Policy Center and the National Urban Coalition. Mr. Reilly is Co-Chairman of the National Commission on Energy Policy.
Jonathan D. Smidt (1)	36	2007	Jonathan D. Smidt has served as a Director of EFH Corp. since October 2007. He has been with KKR since 2000, where he is a member of the firm’s Energy and Natural Resources industry team. Currently, he is a director of Laureate Education Inc. and TXU Energy.
John F. Young (2)(3)	52	2008	John F. Young has served as a Director and President and Chief Executive of EFH Corp. since January 2008. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon from March 2003 to January 2008 including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation. Mr. Young is also a director of Luminant.
Kneeland Youngblood (1)	53	2007	Kneeland Youngblood has served as a Director of EFH Corp. since October 2007. He is founding partner of Pharos Capital Group, a private equity firm that focuses on providing growth and expansion capital to businesses in technology, business services, and health care services. Mr. Youngblood is a director of the following public companies: Starwood Hotels and Resorts Worldwide, Inc., Gap Inc. and Burger King Holdings, Inc. Mr. Youngblood is a member of the Council on Foreign Relations.

(1) Member of Audit Committee.

(2) Member of Executive Committee.

(3) Member of Governance and Public Affairs Committee

(4) Member of Organization and Compensation Committee

231

Executive Officers

The names and information regarding EFH Corp.’s executive officers are set forth below:

Name of Officer	Age	Positions and Offices Presently Held	Date First Elected to Present Offices	Business Experience (Preceding Five Years)
John F. Young	52	President and Chief Executive Officer of EFH Corp.	January 2008	John F. Young was elected President and Chief Executive Officer of EFH Corp. in January 2008. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon Corporation from March 2003 to January 2008, including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation.
Micheal R. Blevins	57	Acting Chief Operating Officer of Luminant	February 2009	Michael R. Blevins was elected Acting Chief Operating Officer of Luminant in February 2009. Previously, Mr. Blevins was Executive Vice President and Chief Nuclear Officer of Luminant since March 2008 having served as Senior Vice President and Chief Nuclear Officer of Luminant since October 2003.
James A. Burke	40	President and Chief Executive of TXU Energy	August 2005	James A. Burke was elected President and Chief Executive of TXU Energy in August 2005. Previously, Mr. Burke was Senior Vice President Consumer Markets of TXU Energy. Prior to joining EFH Corp. in 2004, Mr. Burke was President and Chief Operating Officer of Gexa Energy.
David A. Campbell	40	President and Chief Executive of Luminant	June 2008	David A. Campbell was elected President and Chief Executive of Luminant in June 2008. Previously, Mr. Campbell was Executive Vice President and Chief Financial Officer of EFH Corp. since April 2007 having served as Acting Chief Financial Officer since March 2006 and Executive Vice President since May 2004. Prior to joining EFH Corp. in 2004, Mr. Campbell was a Principal of McKinsey & Company, Inc.
M. Rizwan Chand	45	Executive Vice President of EFH Corp.	May 2008	M. Rizwan Chand was elected Executive Vice President of EFH Corp. in May 2008. Previously, Mr. Chand was Senior Vice President of EFH Corp. Prior to joining EFH Corp. in 2005, Mr. Chand was Vice President of Human Resources and Corporate Relations for Kennametal, Inc.

232

Charles R. Enze	55	Executive Vice President and Chief Executive of Luminant Construction	September 2006	Charles R. Enze was elected Executive Vice President and Chief Executive of Luminant Construction in September 2006. Prior to joining EFH Corp. in 2006, Mr. Enze was Vice President of Engineering and Projects for Shell International Exploration & Production.
M. S. Greene	63	Vice Chairman of EFH Corp.	June 2008	M. S. Greene was elected Vice Chairman of EFH Corp. in June 2008. Previously Mr. Greene held several other offices including President and Chief Executive of Luminant, Chairman of the Board, President and Chief Executive of TXU Power, Executive Vice President of TCEH, and Vice Chairman, Chief Executive and President of Oncor.
Paul M. Keglevic	55	Executive Vice President and Chief Financial Officer of EFH Corp.	July 2008	Paul M. Keglevic was elected Executive Vice President and Chief Financial Officer of EFH Corp. in July 2008. Before joining EFH Corp., he was an audit partner at PricewaterhouseCoopers. Mr. Keglevic was Pricewaterhouse-Coopers Utility Sector Leader from 2002 to 2008 and Clients and Sector Assurance Leader from 2007 to 2008.
M. A. McFarland	39	Executive Vice President and Chief Commercial Officer of Luminant and Executive Vice President of EFH Corp.	July 2008	M. A. McFarland was elected Executive Vice President and Chief Commercial Officer of Luminant and Executive Vice President of EFH Corp. in July 2008. Before joining Luminant, Mr. McFarland served as Senior Vice President of Mergers, Acquisitions and Divestitures and as a Vice President in the wholesale marketing and trading division power team at Exelon.
Robert C. Walters	50	Executive Vice President and General Counsel of EFH Corp.	March 2008	Robert C. Walters was elected Executive Vice President and General Counsel of EFH Corp. in March 2008. Prior to joining EFH Corp., Mr. Walters was a Partner of Vinson & Elkins LLP and served on the firm’s management committee. Mr. Walters was co-managing partner of the Dallas office of Vinson & Elkins LLP from 1998 through 2005.

There is no family relationship between any of the above-named executive officers.

Audit Committee Financial Expert

The Board of Directors has determined that Donald L. Evans is an “Audit Committee Financial Expert” as defined in Item 407(d)(5) of SEC Regulation S-K.

233

Code of Conduct

EFH Corp. maintains certain corporate governance documents on EFH Corp’s website atwww.energyfutureholdings.com. EFH Corp.’s Code of Conduct can be accessed by selecting “Investor Relations” on the EFH Corp. website. EFH Corp.’s Code of Conduct applies to all of its employees, officers (including the Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer) and directors. Any amendments to the Code of Conduct will be posted on EFH Corp.’s website. Printed copies of the corporate governance documents that are posted on EFH Corp.’s website are also available to any investor upon request to the Secretary of EFH Corp. at 1601 Bryan Street, Dallas, Texas 75201-3411.

Procedures for Shareholders to Nominate Directors; Arrangement to Serve as Directors

The procedures by which security holders may recommend nominees to EFH Corp.’s Board of Directors that were contained in EFH Corp.’s Corporate Governance Guidelines prior to the Merger were eliminated as a result, and at the effective time, of the Merger.

The Amended and Restated Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC, the general partner of Texas Holdings, generally requires that the members of Texas Energy Future Capital Holdings LLC take all necessary action to ensure that the persons who serve as its managers also serve on the EFH Corp. Board of Directors. In addition, Mr. Young’s employment agreement provides that he will continue to serve as a member of the Board of Directors during the time he is employed by EFH Corp.

Because of these requirements, together with Texas Holdings’ controlling ownership of EFH Corp.’s outstanding common stock, there is no policy or procedure with respect to shareholder recommendations for nominees to the EFH Corp. Board of Directors.

234

Item 11. EXECUTIVE COMPENSATION

Compensation Committee, Compensation Committee Interlocks and Insider Participation

The current Organization and Compensation Committee of the Board of Directors is comprised of four non-employee directors: Arcilia C. Acosta, Donald L. Evans, Marc S. Lipschultz and Kenneth Pontarelli. There were no relationships among our executive officers, members of the Organization and Compensation Committee or entities whose executives served on the Organization and Compensation Committee that required disclosure under applicable SEC rules and regulations. For a description of related person transactions involving members of the Organization and Compensation Committee, see “Related Person Transactions.”

Compensation Discussion and Analysis

Overview

The EFH Corp. Board of Directors (“Board”) has an Organization and Compensation Committee that establishes and assesses our executive compensation program (the “O&C Committee”). The O&C Committee is comprised of four non-employee directors: Arcilia C. Acosta, Donald L. Evans, Marc S. Lipschultz and Kenneth Pontarelli.

The responsibilities of the O&C Committee include:

• determining and overseeing EFH Corp.’s executive compensation program, including making recommendations to the Board with respect to the adoption, amendment or termination of incentive compensation, equity-based and other executive compensation and benefits plans, policies and practices, and

• evaluating the performance of our Chief Executive Officer and other executive officers and, ultimately, approving executive compensation based on those evaluations.

In determining the compensation of our executive officers (other than the CEO), including the executive officers named in the Summary Compensation Table (the “Named Executive Officers”), the O&C Committee seeks the input of our CEO. At the end of each year, our CEO assesses the performance of each of these executive officers against targeted business unit and individual goals and objectives for that year and provides recommendations to the O&C Committee. The O&C Committee and the CEO then review the CEO’s assessments of those executives and, in that context, the O&C Committee approves the executive officers’ compensation.

In assessing the EFH Corp.’s and the CEO’s performance, the O&C Committee follows a thorough and detailed process, including a self-assessment prepared by the CEO reflecting the full year performance of the business, a follow up meeting with the CEO to further discuss his performance and address any questions or comments the O&C Committee may have about his performance, and a final meeting where the official full year financial, operating, and other results of EFH Corp. are evaluated and approved by the O&C Committee.

The O&C Committee may use, from time to time, independent compensation consultants to advise on executive compensation issues, including salary surveys and performance measurement criteria. We assess our compensation program against publicly-traded utility, energy and general industry companies, as well as known practices in private equity-owned companies, utilizing a variety of market reference points and benchmarks, median competitive data, and performance measurements.

235

Compensation Philosophy

Overview

We have a pay-for-performance compensation philosophy, which places an emphasis on pay-at-risk. In other words, a significant portion of an executive officer’s compensation is made up of variable, at-risk incentive compensation. As a result of our pay-for-performance compensation philosophy, our compensation program is intended to compensate executive officers appropriately for their contribution to the attainment of financial, operational and strategic objectives. In addition, we believe it is important to strongly align the interests of our executive officers and stockholders through equity-based compensation, by giving our executive officers an opportunity to invest in our common stock and through the use of stock options. Equity ownership, coupled with other incentives, is an important component of our compensation program.

To achieve our pay-for-performance compensation philosophy, we believe that:

• compensation plans should balance both long-term and short-term objectives;

• the overall compensation program should emphasize variable compensation elements that have a direct link to overall corporate performance and stockholder value, and

• an executive officer’s individual compensation level should be based upon an evaluation of the financial and operational performance of that executive officer’s business unit (such as productivity, reliability, safety and customer satisfaction) as well as the executive officer’s individual performance.

We believe our pay-for-performance compensation philosophy supports EFH Corp. by:

• aligning performance measures with our business objectives to drive the financial and operational performance of EFH Corp. and its business units;

• rewarding business unit and individual performance by providing compensation levels consistent with the level of contribution and degree of accountability;

• attracting and retaining the best performers, and

• strengthening the correlation between the long-term interests of our executive officers and the interests of stockholders through equity compensation and investment opportunities.

236

Elements of Compensation

As a result of these underlying compensation principles, the compensation program for our Named Executive Officers principally consists of:

• a base salary;

• the opportunity to earn an annual performance bonus based on the achievement of specific corporate, business unit and individual performance goals;

• long-term equity incentive awards—primarily in the form of options to purchase shares of our common stock (the “Stock Option Awards”) under our 2007 Stock Incentive Plan for Key Employees of EFH Corp. and Affiliates (the “2007 Stock Incentive Plan”);

• the opportunity to participate in our Salary Deferral Program and our Thrift (401(k)) Plan and receive company matching contributions, and

• the opportunity to participate in our Retirement Plan and Supplemental Retirement Plan (which has been limited for our competitive, non-regulated businesses to persons employed by us on or before October 1, 2007).

Assessment of Compensation Elements

We try to ensure that the bulk of an executive officer’s compensation is directly linked to our performance. For example, the annual performance bonus is based on the achievement of certain corporate and business unit financial targets and operational targets (such as productivity, growth and customer satisfaction). In addition, the vesting of half of an executive’s Stock Option Awards is contingent upon the attainment of a corporate financial target. We also try to ensure that our executive compensation program is competitive in order to reduce the risk of losing key personnel within our organization.

The following is a discussion of the principal compensation components provided to our executive officers. More detail about each of the compensation elements that follow can be found in the compensation tables and the narrative and footnotes to the tables.

Base Salary

Base salary should reward executive officers for the scope and complexity of their position and the level of responsibility required. We believe that a competitive level of base salary is required to attract qualified talent.

The O&C Committee reviews base salaries annually to ensure they are market-competitive for attraction and retention purposes. The O&C Committee may also review an executive officer’s base salary to the extent an executive officer is given a promotion or in the event an executive officer’s responsibilities are significantly increased.

We want to ensure cash compensation is competitive and sufficient to entice key executive officers to remain with us, recognizing our high performance expectations (across a broad set of operational, financial, customer service and community-oriented goals and objectives) and the higher risk levels associated with being a significantly-leveraged company.

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2008 Base Salary for EFH Corp.’s Named Executive Officers

Name	Title (as of December 31, 2008)	Base Salary as of 12/31/08
John F. Young (1)	President and Chief Executive Officer of EFH Corp.	$	1,000,000
Paul M. Keglevic (2)	Executive Vice President and Chief Financial Officer of EFH Corp.	$	600,000
David A. Campbell (3)	Chief Executive Officer of Luminant	$	600,000
M. S. Greene (4)	Vice Chairman of EFH Corp.	$	650,000
James A. Burke	Chief Executive Officer of TXU Energy	$	600,000
Robert C. Walters (5)	Executive Vice President and General Counsel of EFH Corp.	$	575,000
M.A. McFarland (6)	Executive Vice President of EFH Corp. and Executive Vice President and Chief Commercial Officer of Luminant	$	500,000
David P. Poole (7)	Former Executive Vice President & General Counsel of EFH Corp.		N/A

(1) Mr. Young commenced his employment with EFH Corp. in January 2008.

(2) Mr. Keglevic commenced his employment with EFH Corp. in July 2008.

(3) Mr. Campbell served as a Co-Chief Executive Officer of EFH Corp. until Mr. Young was hired and the Chief Financial Officer of EFH Corp. through June 2008, after which he assumed responsibility as the Chief Executive Officer of Luminant.

(4) Mr. Greene served as a Co-Chief Executive Officer of EFH Corp. until Mr. Young was hired and the Chief Executive Officer of Luminant through June 2008, after which he assumed responsibility as the Vice Chairman of EFH Corp.

(5) Mr. Walters commenced his employment with EFH Corp. in March 2008.

(6) Mr. McFarland commenced his employment with EFH Corp. in July 2008.

(7) Mr. Poole terminated his employment with EFH Corp. in March 2008.

Executive Annual Incentive Plan

The Executive Annual Incentive Plan provides an annual performance-based cash bonus for the successful attainment of certain annual operational and financial goals that are established at each of the corporate and business unit levels by the O&C Committee at the beginning of each year. Under the terms of the plan, performance against the targets established by the O&C Committee drive bonus funding. These targets are generally set at challenging levels to ensure they are high performance goals. Based on the level of attainment of these performance targets, an aggregate plan funding percentage amount for all participants is determined. To calculate an executive officer’s award amount, the executive officer’s corporate/business unit funding percentages are multiplied by the executive officer’s target incentive level, which is computed as a percentage of annualized base salary. Based on the executive officer’s performance, an individual performance modifier is multiplied to the calculated award to determine the final award under the plan. An individual performance modifier is based on the CEO’s and the O&C Committee’s review and evaluation of the executive officer’s performance. The individual performance modifier can range from an outstanding rating (200%) to an unacceptable rating (0%). The aggregate plan funding amount is limited to 200%, or two times, the aggregate target incentives of all participants.

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The following table provides a summary of the 2008 annual incentive awards for each Named Executive Officer.

2008 Annual Incentives for Our Named Executive Officers

Name	Target (% of salary)		Target Award ($ Value)		Actual Award(1)
John F. Young (1)	100	%	$	1,000,000	1,418,000
Paul M. Keglevic (2)	75	%	$	450,000	613,800
David A. Campbell (3)	75	%	$	450,000	625,950
M. S. Greene (4)	75	%	$	487,500	521,625
James A. Burke (5)	75	%	$	450,000	473,918
Robert C. Walters (6)	75	%	$	431,250	695,175
M.A. McFarland (7)	75	%	$	375,000	529,032
David P. Poole	N/A			N/A	N/A

The O&C Committee establishes the targets and approves actual performance against those targets for the Executive Annual Incentive Plan. The 2008 targets included both financial and operational measures. Targets set for EFH Corp. and EFH Corporate Services were primarily financial; however the targets set for both Luminant and TXU Energy included both financial and operational measures such as safety, generation, construction performance, customer growth and customer satisfaction.

The performance measures for EFH Corp. were comprised of operational EBITDA and cash flow for EFH Corp. as well as total EFH Corp. total spend (Sales, General & Administrative (SG&A); Operating & Maintenance (O&M); and Capital Expenditures) as shown in the table of performance measures below. The operational EBITDA is a non-GAAP financial measure. Operational EBITDA is defined as EBITDA as adjusted by the O&C Committee as it deems appropriate in connection with its evaluation and compensation of our executive officers. Operational EBITDA is an internal measure used only for performance management purposes and EFH Corp. does not intend for operational 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 GAAP. Operational EBITDA is not the same as Adjusted EBITDA, which is disclosed elsewhere in this form 10-K and defined in the glossary to this form 10-K.

The performance measures for EFH Corporate Services were comprised of operational EBITDA for EFH Corp., EFH Corp. total spend (as defined above) and controllable costs for EFH Corporate Services. The performance measures for Luminant included Luminant specific EBITDA and cash flow, cost metrics (fuel costs; O&M; SG&A; and capital expenditures), and operational metrics that measured safety, generation and a construction performance. The performance metrics for TXU Energy included both financial and operational metrics, including TXU Energy EBITDA and controllable SG&A costs. TXU Energy’s operational metrics included residential customer growth, customer satisfaction and achievement of key milestones in the upgrade to its major customer care system.

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Performance against the applicable metrics for each executive officer is detailed below.

EFH Corp. Performance Metrics – used to measure the performance of Mr. Young

Metric	Weight		Performance(1)		Payout %
EFH Corp. EBITDA	50	%	79	%	40	%
EFH Corp. Cash Flow	20	%	200	%	40	%
EFH Corp. Total Spend	30	%	123	%	37	%
					117	%
Less safety modifier (10% of calculated payout)					(12	)%
					105	%

(1)    Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

EFH Corp. Services Performance Metrics – used to measure the performance of Messrs. Keglevic, Greene, Campbell, Walters and McFarland

Metric	Weight		Performance(1)		Payout %
EFH Corp. EBITDA	40	%	79	%	32	%
EFH Corp. Total Spend	30	%	123	%	37	%
EFH Corp. Services Company Costs	30	%	185	%	55	%
					124	%

(1)    Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

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Luminant Performance Metrics – used to measure the performance of Messrs. Greene and Campbell

Metric	Weight		Performance(1)		Payout %
Luminant EBITDA)	25	%	84	%	21	%
Luminant Cash Flow	25	%	132	%	33	%
Fuel Costs	3	%	0	%	0	%
O&M/SG&A Costs	4	%	100	%	4	%
Capital Expenditure	3	%	100	%	3	%
Luminant Energy Incremental Value	10	%	70	%	7	%
Safety Incidents	10	%	0	%	0	%
Generation (GADS)	10	%	60	%	6	%
Construction Index	10	%	160	%	16	%
					90	%

(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

TXU Energy Performance Metrics – used to measure the performance of Mr. Burke

Metric	Weight		Performance(1)		Payout %
TXU Energy EBITDA	42.4	%	52	%	22	%
TXU Energy SG&A	14.4	%	133	%	19	%
Customer Growth	14.4	%	163	%	24	%
Customer Satisfaction	14.4	%	100	%	14	%
SAP Project	14.4	%	147	%	21	%
					100	%

(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

After approving the actual performance against the applicable target metrics under the Executive Annual Incentive Plan, the O&C Committee reviews the performance of each of our executive officers on an individual and comparative basis. Based on this review, which includes an analysis of both objective and subjective criteria, the O&C Committee approves an individual modifier for each executive to determine his final annual incentive award. For 2008, the personal modifier for each of our Named Executive Officers increased his actual award, reflecting the strong performance of a new leadership team during a challenging financial and economic market.

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(1) Mr. Young’s incentive award is based on EFH Corp.’s strong performance in 2008. In Mr. Young’s first year, he successfully set the groundwork for long term success for the company. In 2008, he rebuilt the senior management team of the company and helped to clearly define our vision, values and operating principles and strategy. Mr. Young focused on risk management, to more effectively manage the current and future commodity volatility, as well as continuous improvement in operating performance across the company’s businesses. Given these achievements, the O&C Committee increased Mr. Young’s incentive award and did not prorate his incentive award for time spent at the company during 2008.

(2) Mr. Keglevic’s incentive award is based on the EFH Corp. Services performance measures and his individual performance. Mr. Keglevic joined the company in July 2008 and quickly and successfully began the transformation of EFH Corp.’s financial processes, including processes and structures for understanding and managing the performance of the businesses, managing our risks and preserving effective liquidity levels. Given these achievements, the O&C Committee increased Mr. Keglevic’s incentive award and did not prorate his incentive award for time spent at the company during 2008.

(3) Mr. Campbell was a Co-Chief Executive Officer of EFH Corp. through January 2008 and the Chief Financial Officer of EFH Corp. through June 2008, after which he served as President and Chief Executive Officer of Luminant. Accordingly, his incentive award was based 50% on EFH Corp. performance and 50% on Luminant performance. Mr. Campbell provided strong leadership at both EFH Corp., through a transition period coupled with a challenging commodity, financial and economic market, and Luminant, where he drove strong operational improvements and results in 2008. Given these achievements, the O&C Committee increased Mr. Campbell’s incentive award.

(4) Mr. Greene was a Co-Chief Executive Officer of EFH Corp. through January 2008 and the Chief Executive Officer of Luminant through June 2008, after which he accepted the position of Vice Chairman of EFH Corp. His incentive award was based 50% on Luminant performance and 50% on EFH Corp. Services performance. Mr. Greene provided strong leadership to Luminant through the first six months of 2008 and to EFH Corp. during 2008.

(5) Mr. Burke’s incentive award was based 100% on the performance of TXU Energy. Mr. Burke provided effective leadership of TXU Energy through a challenging year during which TXU Energy set itself apart from its competitors. Given these achievements, the O&C Committee increased Mr. Burke’s incentive award.

(6) Mr. Walters’ incentive award is based 100% on the EFH Corp. Services performance. The O&C Committee increased Mr. Walters’ incentive award based on his individual performance, reflecting his leadership and results in managing significant legal issues and developing a strong public affairs strategy and team.

(7) Mr. McFarland joined EFH Corp. mid-year and has demonstrated strong performance as our wholesale commercial operations delivered significantly improved performance over 2007. Due to the nature of Mr. McFarland’s role, where he provides services at both Luminant and EFH Corp. Services, his award is based 75% on the performance of Luminant business units and 25% on the performance of EFH Corp. Services. Luminant overall business units’ performance was 98%. Because of his effective leadership and results, the O&C Committee increased Mr. McFarland’s incentive award.

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Long-Term Equity Incentives

In December 2007, our Board approved and adopted the 2007 Stock Incentive Plan. The purpose of the 2007 Stock Incentive Plan is to:

• promote our long-term financial interests and growth by attracting and retaining management and other personnel with the training, experience and ability to enable them to make a substantial contribution to the success of our business;

• motivate management and other personnel by means of growth-related incentives to achieve long-range goals, and

• align the interests of management with those of our stockholders through opportunities for stock (or stock-based) ownership in EFH Corp.

In February 2008, Mr. Young was granted 7,500,000 Stock Option Awards. In May 2008, Messrs. Campbell, Greene, Burke and Walters were granted 4,000,000, 2,000,000, 2,450,000 and 2,000,000, Stock Option Awards, respectively. In December 2008, Messrs. Keglevic and McFarland were granted 2,500,000 and 2,000,000 Stock Option Awards, respectively. All awards were granted with the terms described below. In the future, we may also make additional discretionary grants of options or stock to reward high performance or achievement.

Many of our executive officers have direct, illiquid, equity investments in EFH Corp., a privately-held company, as a result of the significant investments in EFH Corp. made by such executive officers. We believe that the management investment and ownership of EFH stock, along with the Stock Option Awards, provides significant retentive value to us for many reasons, most notably:

• Due to limitations on transferability until the occurrence of certain liquidity events, an investment in our common stock is illiquid while the executive remains employed by us. In addition, if an executive voluntarily terminated his or her employment with us, generally, the company could compel him or her to sell that stock back to us for a price equal to the price paid by the executive for the stock.

• Half of all of the Stock Option Awards granted are time-based and vest over a five year period (the “Time-Vesting Options”), except with regard to Mr. Greene whose Time Vesting Options vest over a two year period. The other half of the Stock Option Awards are performance-based and vesting is dependent upon EFH Corp. achieving certain performance targets (the “Performance-Vesting Options”). In addition, if in the event of a change in control certain investment returns are achieved for our equity-holders, the Performance-Options will vest.

Because half of the Stock Option Awards granted are performance-based, we believe the equity component of our compensation program motivates our executive officers to achieve top operational and financial performance and further aligns our executive officers’ interests with the interests of our stockholders. In deciding whether to vest the Performance-Vesting Options, the O&C Committee considers EFH Corp.’s quantitative performance against certain EBITDA targets, which may be adjusted as described below. The O&C Committee also has the discretion to consider other qualitative and quantitative criteria.

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The material terms of our Stock Option Awards are as follows:

• The exercise price is an amount equal to the fair market value of a share of our common stock on the date an option is granted, which was $5.00 for the options that were granted to Mr. Young in February 2008; Messrs. Campbell, Greene, Burke and Walters in May 2008 and Messrs. Keglevic and McFarland in December 2008.

• The fair market value of a share of our common stock is reviewed semi-annually by an independent valuation firm, which makes a recommendation that is reviewed and, if acceptable, approved by our Board.

• The options have a ten-year term.

• Half of the Stock Option Awards are Time-Vesting Options and vest as follows: for Messrs. Young, Campbell, Greene, Burke and Walters, the Time-Vesting Options vest in 20% increments on each of the first five anniversaries of October 10, 2007, the date that the Merger was completed, subject to the each executive’s continued employment with EFH Corp. Mr. Greene’s Time-Vesting Options vest in 50% increments on each of the first two anniversaries of October 10, 2007. Messrs. Keglevic and McFarland’s Time-Vesting Options vest in 20% increments on each of the first five anniversaries of their employment, which is July 1, 2008 and July 7, 2008, respectively.

• The other half of the Stock Option Awards are Performance-Vesting Options and vest in 20% increments on each of the first five anniversaries of December 31, 2007, subject to the grantee’s continued employment with us and our achievement of the annual EBITDA target for the given fiscal year (or certain cumulative performance targets) as detailed in the stock option agreements.

The performance options have a catch up provision for vesting. If we do not achieve the performance target for any particular fiscal year, but we do achieve the sum of two- or three-years of EBITDA performance targets at the end of either of the two immediately subsequent fiscal years, then any Performance-Vesting Options that did not vest because of a missed performance target in those prior years will vest.

When the O&C Committee reviews EBITDA for purposes of determining our performance against the applicable annual EBITDA target, it includes our earnings before interest, taxes, depreciation and amortization plus transaction, management and/or similar fees paid to the Sponsor Group, together with such adjustments as the O&C Committee shall determine appropriate in its discretion after good faith consultation with our Chief Executive Officer and the Chief Financial Officer, including adjustments consistent with those included in the comparable definitions in TCEH’s Senior Secured Facilities to the extent considered appropriate for management compensation purposes.

Our EBITDA targets are also expected to be adjusted for acquisitions, divestitures or major capital investment initiatives to the extent that they were not contemplated in the financial plan that was presented by our executive officers to the Sponsor Group (the “Financial Plan”).

The EBITDA targets are intended to measure achievement of the Financial Plan and the adjustments to EBITDA described above primarily represent elements of our performance that are either beyond the control of management or were not predictable at the time the Financial Plan was submitted.

Some or all of the Performance-Vesting Options granted to our executive officers could also vest when certain other events occur, including certain sales by the Sponsor Group of its investment in EFH Corp.

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The actual EBITDA for 2008 of $4,488 million was approximately 97% of the EBITDA target established in the Financial Plan for 2008. Given the relative proximity of the actual EBITDA for 2008 to the established target, as well as EFH Corp.’s strong financial and operational performance during a challenging financial and economic market, the O&C Committee exercised its discretionary authority under the 2007 Stock Incentive Plan and approved the vesting of the 2008 Performance-Vesting Options.

Mr. Young was granted 600,000 restricted stock units in February 2008 under the terms of his employment agreement. All of the restricted stock units were vested upon the grant date; however if Mr. Young terminates his employment with EFH Corp. without good reason prior to February 2010 the restricted stock units will be forfeited.

Mr. Campbell entered into a Deferred Share Agreement with EFH Corp. in May 2008, pursuant to which he agreed to forego certain payments he was entitled to receive in return for a certain number of deferred shares of our common stock. Pursuant to the terms of his Deferred Share Agreement, Mr. Campbell agreed to reinvest a substantial portion of the amount that he was entitled to receive. As a result of the reinvestment, Mr. Campbell became entitled to receive 500,000 deferred shares of our common stock, with each share being valued at $5.00 based upon the fully diluted equity of EFH Corp. The shares will be distributed to Mr. Campbell on the earlier of termination of employment by EFH Corp. or a change in the effective control of EFH Corp.

Mr. Keglevic was granted 225,000 deferred shares in July 2008 under the terms of his employment agreement. One-half of the deferred shares will vest in July 2011 and the remaining one-half will vest in July 2013.

Deferred Compensation and Retirement Plans

Salary Deferral Program:Our Salary Deferral Program allows participating employees, including our executive officers, to defer a portion of their salary and annual incentive award and to receive a matching award based on their salary deferrals. Executive officers can defer up to 50% of their base salary and up to 100% of any incentive-based award for seven years or until they retire. We match 100% of deferrals up to 8% of salary deferred under the program. We do not match deferred incentive-based awards. We believe that the program encourages employee retention because, generally, participants who terminate their employment with us prior to the seven year vesting period forfeit our matching contribution.

Please refer to the narrative that follows the Nonqualified Deferred Compensation table for a more detailed description of the Salary Deferral Program.

Retirement Plan:We maintain a retirement plan, which is qualified under applicable provisions of the Code and is a benefit for certain employees that were employed by us prior to October 1, 2007. Our Retirement Plan contains both a traditional final average pay component and a cash balance component. Effective January 1, 2002, we changed our defined benefit plan from a traditional final average pay design to a cash balance design. This change was made to better align our retirement program with competitive practices. In late 2001, participants in the Retirement Plan were extended an opportunity to remain in the traditional final average pay component or transition to the cash balance component. Mr. Greene (the only named-executive officer then a participant in the Retirement Plan) elected to remain in the traditional final average pay component.

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Eligible employees employed after January 1, 2001 may only participate in the cash balance component of the Retirement Plan. As a result, Messrs. Campbell and Burke are covered under the cash balance component of the Retirement Plan.

Participation in our Retirement Plan has been limited to employees of all of our businesses (other than Oncor) who were employed by us on or before October 1, 2007. As a result Messrs. Young, Keglevic, Walters and McFarland do not participate in the Retirement Plan. For a more detailed description of the Retirement Plan, please refer to the narrative that follows the Pension Benefits table.

Supplemental Retirement Plan: Our Supplemental Retirement Plan provides for the payment of retirement benefits that:

• would otherwise be capped by the Code’s statutory limits for qualified retirement plans;

• include Executive Annual Incentive Plan awards in the definition of earnings (for participants covered by the traditional final average pay component of the Retirement Plan only); and/or

• we or our participating subsidiaries are obligated to pay under contractual arrangements.

Mr. Greene, the executive officer who elected to remain in the traditional final average pay component, is eligible for a supplemental retirement benefit in concert with that plan, which provides for a traditional defined benefit type retirement annuity stream. This feature of the plan is only available to executive officers who participate in the Supplemental Retirement Plan hired prior to January 1, 2001. As such, it is not available to Messrs. Campbell and Burke. Messrs. Campbell and Burke participate in the “make whole” portion of the Supplemental Retirement Plan as it relates to the cash balance component, which only provides for the payment of retirement benefits that would otherwise be capped by the Code, otherwise restricted or for the inclusion of additional accredited service under contractual arrangements.

Participation in our Supplemental Retirement Plan has been limited to employees of all of our businesses (other than Oncor) who were employed by us on or before October 1, 2007. As a result Messrs. Young, Keglevic, Walters and McFarland do not participate in the Supplemental Retirement Plan.

For a more detailed description of the Supplemental Retirement Plan, please refer to the narrative that follows the Pension Benefits table.

Retiree Health Care:

Employees hired prior to January 1, 2002 are generally entitled to receive an employer paid subsidy for retiree health care coverage upon their retirement from EFH Corp. As such, Mr. Greene will be entitled to receive a subsidy from EFH Corp. for retiree health care coverage upon his retirement from EFH Corp. Because Messrs. Young, Keglevic, Campbell, Burke, Walters and McFarland were hired after January 1, 2002, they are not eligible for retiree health coverage.

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Perquisites

We do not believe that a significant amount of perquisites fit within our compensation philosophy. Those perquisites that exist are intended to serve as part of a competitive total compensation program and to enhance the executive officers’ ability to conduct company business. These benefits include financial planning, a preventive physical health exam and reimbursement for certain country club and/or luncheon membership costs.

The following is a summary of perquisites offered to the Named Executive Officers (excluding Mr. Poole) that are not available to all employees:

Executive Financial Planning:We pay for certain executive officers to receive financial planning services. This service is intended to support them in managing their financial affairs, which we consider especially important given the high level of time commitment and performance expectation required of our executive officers. Furthermore, we believe that such service helps ensure greater accuracy and compliance with individual tax regulations by our executive officers.

Annual Executive Physical Health Exam:We pay for certain executive officers to receive annual physical health exams. The health of our executive officers is important given the vital leadership role they play in directing and operating the company. Our executive officers are important assets of EFH Corp. and this benefit is designed to help ensure their health and long-term ability to serve our stakeholders.

Country Club/Luncheon Club Membership:We reimburse our executive officers for certain country club or luncheon club dues and expenses. We provide this perquisite to allow our executive officers to interact with, and cultivate relationships with, other business professionals and key community leaders and officials.

Expenditures for the perquisites outlined above are disclosed by individual in footnotes to the Summary Compensation Table.

Individual Compensation

Compensation of the CEO and the CFO

John F. Young

In January 2008, Mr. John F. Young became our Chief Executive Officer and President. He also serves as a member of our Board. In connection with his employment, we executed a five-year employment agreement with Mr. Young. After the initial five-year term, the employment agreement provides for automatic one year renewal periods unless terminated by EFH Corp. or Mr. Young.

Base Salary: As compensation for his services as CEO and President, Mr. Young is paid an annual base salary equal to $1 million.

Annual Incentive:Mr. Young has the ability to earn a target annual cash bonus equal to 100% of his base salary if he achieves certain annual performance targets established by the Board. Such annual cash bonus may be increased to an amount equal to 200% of his base salary if he achieves certain superior annual performance targets established by the Board. Mr. Young earned a bonus for 2008 of $1,418,000, reflecting the performance of EFH Corp. and his individual performance as previously discussed.

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Long Term Equity Incentive:As part of his employment arrangement, Mr. Young purchased $3 million in shares of our common stock and was granted 7.5 million Stock Option Awards. Mr. Young also received 600,000 restricted stock units, to compensate him for unvested equity compensation he forfeited when he left his former employer to join EFH Corp. Each restricted stock unit entitles Mr. Young to receive one share of our common stock. The restricted stock units were fully vested on the grant date; however if Mr. Young terminates his employment with EFH Corp. without “good reason” prior to the second anniversary of the grant date the restricted stock units will be forfeited.

The employment agreement also entitles Mr. Young to receive other forms of customary compensation such as health and welfare benefits, perquisites, relocation expenses (including a tax gross-up for reimbursed relocation expenses that are required to be included in his income for tax purposes) and reimbursement of business expenses. Mr. Young does not receive any additional compensation for being a member of the Board.

Paul M. Keglevic

In July 2008, Mr. Paul M. Keglevic became our Executive Vice President and Chief Financial Officer. In connection with his employment, we executed a three-year employment agreement with Mr. Keglevic.

Base Salary: As compensation for his services as Executive Vice President and Chief Financial Officer, Mr. Keglevic is paid an annual base salary equal to $600,000.

Annual Incentive: Mr. Keglevic has the ability to earn an annual cash bonus equal to 75% of his base salary if he achieves certain annual performance targets established by the Board. Such annual cash bonus may be increased to an amount equal to 200% of his annual bonus target based on achievement of certain superior annual performance targets established by the Board. In 2008, Mr. Keglevic earned a bonus of $613,800, reflecting the performance of EFH Corp. and his individual performance as previously discussed.

Signing Bonus: Mr. Keglevic was (or will be) paid a signing bonus equal to $550,000 as follows: (i) $250,000 in July 2008; (ii) $150,000 payable in July 2009 and (iii) $50,000 payable in each of July 2010, 2011 and 2012.

Long Term Equity Incentive: Mr. Keglevic was granted 2.5 million Stock Option Awards. Mr. Keglevic also received 225,000 deferred shares of our common stock to compensate him for compensation he forfeited when he left his former employer to join EFH Corp. If Mr. Keglevic is employed by us on the third and fifth anniversaries of his employment (July 2011 and 2013, respectively), 112,500 of such deferred shares shall vest on each such date. If Mr. Keglevic’s employment with us terminates for any reason prior to July 1, 2013 (other than for “cause” or without “good reason”), he will have the right to (i) sell to us all (but not less than all) of the shares of our common stock that have vested pursuant to the deferred share arrangement (if any) for $3,200,000 or (ii) if no shares of our common stock shall have vested, a payment of $3,200,000.

The employment agreement also entitles Mr. Keglevic to receive other forms of customary compensation such as certain health and welfare benefits, certain perquisites and reimbursement of certain business expenses.

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Compensation of Other Named Executive Officers

David A. Campbell

We entered into a new three-year employment agreement with Mr. Campbell in May 2008, which three-year term is automatically extended for successive one-year periods unless terminated by EFH Corp. or Mr. Campbell. The agreement provides that, during the term, Mr. Campbell will be entitled to the terms outlined below:

Base Salary:As compensation for his services as a Co-Chief Executive Officer of EFH Corp. through January 2008, the Chief Financial Officer of EFH Corp. through June 2008, and the Chief Executive Officer of Luminant for the remainder of the year, Mr. Campbell was paid an annual base salary equal to $382,000 through March 25, 2008 and $600,000 for the remainder of the year.

Annual Incentive: Mr. Campbell’s has the ability to earn a cash bonus equal to 75% of his base salary if he achieves certain annual performance targets established by the Board. Such annual cash bonus may be increased to an amount equal to 200% of his annual bonus target based on achievement of certain superior annual performance targets established by the Board. Mr. Campbell earned a bonus for 2008 of $625,950, reflecting the performance of EFH Corp. and Luminant, as well as his individual performance as previously discussed.

Long Term Equity Incentive: In May 2008, Mr. Campbell was granted 4,000,000 Stock Option Awards and received an award of 500,000 deferred shares. Under his Deferred Share Agreement, the deferred shares are to be distributed on the earlier of termination of his employment with EFH Corp., the occurrence of a change in the ownership or effective control of EFH Corp., or a change in the ownership of a substantial portion of the assets of EFH Corp.

Other:Under the terms of his prior employment agreement with TXU Corp., Mr. Campbell was entitled to certain payments if he terminated his employment following a change in control of EFH Corp. In order to retain Mr. Campbell after the Merger, the O&C Committee approved a sign-on bonus of $5,092,250 to offset a significant portion of those forfeited payments.

M. S. Greene

We entered into an employment agreement with Mr. Greene in May 2008. The agreement entitled Mr. Greene to the following individual compensation for 2008:

Base Salary: As compensation for his role as a Co-Chief Executive Officer of EFH Corp. through January 2008, the Chief Executive Officer of Luminant through June 2008 and the Vice Chairman of EFH Corp. for the remainder of the year, Mr. Greene was paid an annual base salary equal to $650,000.

Annual Incentive: Mr. Greene has the ability to earn a cash bonus equal to 75% of his base salary if he achieves certain annual performance targets established by the Board. Such annual cash bonus may be increased to an amount equal to 200% of his annual bonus target based on achievement of certain superior annual performance targets established by the Board. Mr. Greene earned a bonus for 2008 of $521,625, reflecting the performance of EFH Corp. and Luminant, as well as his individual performance as previously discussed.

Long Term Equity Incentive: In accordance with a Deferred Share Agreement, Mr. Greene agreed to forego the right to receive certain payments from EFH Corp. in respect of outstanding equity awards issued prior to the Merger and became entitled to 600,000 deferred shares of our common stock. The shares will be distributed on the earlier of termination of his employment with EFH Corp. or a change in control of EFH Corp. In May 2008, Mr. Greene was granted 2,000,000 Stock Option Awards.

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James A. Burke

We entered into an employment agreement with Mr. Burke in December 2007, which was amended and restated in May 2008. The agreement provides for Mr. Burke’s service as Chief Executive Officer of TXU Energy during a three-year term, commencing October 10, 2007, which term is automatically extended for successive one-year periods unless terminated by us or Mr. Burke. The agreement provides that, during the three year term, Mr. Burke will be entitled to the terms outlined below:

Base Salary: As compensation for his services as Chief Executive Officer of TXU Energy, Mr. Burke is paid an annual base salary equal to $600,000.

Annual Incentive: Mr. Burke has the ability to earn a cash bonus equal to 75% of his base salary if he achieves certain annual performance targets established by the Board. Such annual cash bonus may be increased to an amount equal to 200% of his annual bonus target based on achievement of certain superior annual performance targets established by the Board. Mr. Burke earned a bonus for 2008 of $473,918, reflecting the performance of TXU Energy and his individual performance as previously discussed.

Long Term Equity Incentive: In accordance with a Deferred Share Agreement, Mr. Burke agreed to forego the right to receive certain payments from EFH Corp. in respect of outstanding equity awards issued prior to the Merger and became entitled to 450,000 deferred shares of our common stock. The shares will be distributed on the earlier of termination of his employment with EFH Corp. or a change in control of EFH Corp. In May 2008, Mr. Burke was granted 2,450,000 Stock Option Awards.

Robert C. Walters

We entered into an employment agreement with Mr. Walters in May 2008 which three-year term is automatically extended for successive one-year periods unless terminated by EFH Corp. or Mr. Walters. The agreement entitled Mr. Walters to the following individual compensation for 2008:

Base Salary: As compensation for his services as Executive Vice President and General Counsel of EFH Corp., Mr. Walters is paid an annual base salary equal to $575,000.

Signing Bonus: Mr. Walters was paid a signing bonus equal to $100,000 in April 2008.

Annual Incentive: Mr. Walters has the ability to earn a cash bonus equal to 75% of his base salary if he achieves certain annual performance targets established by the Board. Such annual cash bonus may be increased to an amount equal to 200% of his annual bonus target based on achievement of certain superior annual performance targets established by the Board. Mr. Walters earned a bonus for 2008 of $695,175, reflecting the performance of EFH Corp. in 2008 and his individual performance as previously discussed.

Long Term Equity Incentive: In May 2008, Mr. Walters was granted 2,000,000 Stock Option Awards.

M. A. McFarland

We entered into an employment agreement with Mr. McFarland in July 2008. The agreement provides for Mr. McFarland’s service as Executive Vice President of EFH Corp. and Executive Vice President and Chief Commercial Officer of Luminant during a three-year term, commencing July 7, 2008, which term is automatically extended for successive one-year periods unless terminated by EFH Corp. or Mr. McFarland. The agreement provides that, during the three year term, Mr. McFarland will be entitled to the terms outlined below:

Base Salary: As compensation for his services as Executive Vice President of EFH Corp. and Executive Vice President and Chief Commercial Officer of Luminant, Mr. McFarland is paid an annual base salary equal to $500,000.

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Signing Bonus: Mr. McFarland was paid a signing bonus equal to $150,000 in July 2008.

Annual Incentive: Mr. McFarland has the ability to earn a cash bonus equal to 75% of his base salary if he achieves certain annual performance targets established by the Board. Such annual cash bonus may be increased to an amount equal to 200% of his annual bonus target based on achievement of certain superior annual performance targets established by the Board. Mr. McFarland earned a bonus for 2008 of $529,032, reflecting the performance of EFH Corp. and Luminant as well as his individual performance as previously discussed.

Long Term Equity Incentive: In December 2008, Mr. McFarland was granted 2,000,000 Stock Option Awards. In accordance with a Deferred Share Agreement, Mr. McFarland also received 100,000 deferred shares. These shares will vest provided Mr. McFarland is employed by EFH Corp. in July 2010. The shares will also vest upon a change in control of EFH Corp. or upon his termination for “good reason”, without “cause”, death or disability.

David P. Poole

Mr. Poole was EFH Corp.’s former General Counsel. He left the company in March 2008. We entered into an employment agreement with Mr. Poole in May 2004, which was amended in September 2007, October 2007 and January 2008. In 2008, Mr. Poole’s base salary was $66,666 per month. Also, in January 2008, Mr. Poole received lump sum cash payments of (i) $982,400, representing the cash severance that would be due to him under his employment agreement upon his termination from EFH Corp. and (ii) $4,155,000, representing the amount agreed to be paid with regard to his ungranted 2008 and 2009 long term performance units under the company’s pre-Merger equity incentive plan.

Contingent Payments

We have entered into employment agreements with Messrs. Young, Keglevic, Greene, Campbell, Burke, Walters and McFarland. Each of the employment agreements provides that certain payments and benefits will be paid upon the expiration or termination of the agreement under various circumstances, including termination without cause, resignation for good reason and termination of employment within a fixed period of time following a change in control. We believe these provisions are important in order to attract and retain the caliber of executive officers that our business requires and provide incentive for our executive officers to fully consider potential changes that are in our and our shareholders’ best interest, even if such changes would result in the executive officers’ termination. For a description of the applicable provisions in the employment agreements and our change in control policy and severance plan see “Potential Payments upon Termination or Change in Control.”

Accounting and Tax Considerations

Accounting Considerations

Under current accounting rules, specifically SFAS 123R, the total amount of compensation expense to be recorded for stock-based awards (e.g., Stock Option Awards granted under the 2007 Stock Incentive Plan) is based on the fair value of the award on the grant date. This fair value is then recorded as expense over the vesting period, with an offsetting increase in paid-in capital. The amount of compensation expense is not subsequently adjusted for changes in our share price, for the actual number of shares distributed, or for any other factors except for true-ups related to estimated forfeitures compared to actual forfeitures.

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Income Tax Considerations

Section 162(m) of the Code limits the tax deductibility by a publicly held company of compensation in excess of $1 million paid to the CEO or any other of its three most highly compensated executive officers other than the principal financial officer. Because EFH Corp. is a privately-held company, Section 162(m) will not limit the tax deductibility of any executive compensation for 2008.

The O&C Committee administers our compensation programs with the good faith intention of complying with Section 409A of the Code.

Organization and Compensation Committee Report

The O&C Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth in this Form 10-K. Based on this review and discussions, the committee recommended to the Board that the Compensation Discussion and Analysis be included in this Form 10-K.

Organization and Compensation Committee

Donald L. Evans, Chair

Arcilia C. Acosta

Marc S. Lipschultz

Kenneth Pontarelli

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The following table provides information for the fiscal years ended December 31, 2006, 2007 and 2008 regarding the aggregate compensation paid to our Named Executive Officers.

Summary Compensation Table

Name and Principal Position	Year	Salary ($)(1)	Bonus ($)(2)	Stock Awards ($)(3)	Non-Equity Incentive Plan Compensation ($)(4)	Change in Pension Value and Non-qualified Deferred Compensation Earnings ($)(5)	All Other Compensation ($)(6)	Total ($)
John F. Young President & CEO of EFH Corp.	2008	912,500	N/A	4,311,250	1,418,000	0	462,258	7,104,008
	2007	N/A	N/A	N/A	N/A	N/A	N/A	N/A
	2006	N/A		N/A	N/A	N/A	N/A	N/A
Paul M. Keglevic EVP & Chief Financial Officer of EFH Corp.	2008	293,182	250,000	1,499,550	613,800	0	88,508	2,745,040
	2007	N/A	N/A	N/A	N/A	N/A	N/A	N/A
	2006	N/A	N/A	N/A	N/A	N/A	N/A	N/A
David A. Campbell President & CEO Luminant	2008	545,500	5,092,250	1,566,000	625,950	22,779	75,915	7,928,394
	2007	382,000	0	1,339,728	300,481	14,667	2,342,814	4,379,690
	2006	382,000	0	1,311,787	230,000	30,639	53,682	2,008,108
M. S. Greene Vice Chairman of EFH Corp.	2008	650,000		1,259,250	521,625	480,428	232,630	3,143,933
	2007	536,792		596,284	384,065	189,411	347,747	2,054,299
	2006	507,000		1,145,979	220,000	1,222,893	229,765	3,325,637
James A. Burke President & CEO of TXU Energy	2008	600,000		959,175	473,918	25,501	639,136	2,697,730
	2007	342,712		454,478	274,050	9,864	978,189	2,059,293
	2006	275,004		512,932	100,000	15,962	52,233	956,131
Robert C. Walters EVP & General Counsel of EFH Corp.	2008	435,609	100,000	783,000	695,175	N/A	44,249	2,058,033
	2007	N/A		N/A	N/A	N/A	N/A	N/A
	2006	N/A		N/A	N/A	N/A	N/A	N/A
M.A. McFarland EVP EFH Corp. & EVP & Chief Commercial Officer of Luminant	2008	236,744	150,000	1,221,751	529,032	0	87,725	2,225,252
	2007	N/A	N/A	N/A	N/A	N/A	N/A	N/A
	2006	N/A	N/A	N/A	N/A	N/A	N/A	N/A
David P. Poole Former EVP & General Counsel of EFH Corp.	2008	291,108		0	0	16,769	7,629,785	7,937,662
	2007	307,000		1,099,176	220,487	13,388	2,627,981	4,268,032
	2006	307,000		841,275	120,000	22,696	43,082	1,334,053

(1) The base salary for Messrs. Young, Keglevic, McFarland and Poole represent salaries for a partial year. Messrs. Young, Keglevic and McFarland commenced employment with EFH Corp. in January 2008, July 2008 and July 2008, respectively and Mr. Poole terminated his employment in March 2008.

(2) Mr. Keglevic’s employment agreement provided that we pay him a signing bonus equal to $550,000 as follows: (i) $250,000 payable in July 2008; (ii) $150,000 payable in July 2009 and (iii) $50,000 payable in July 2010, 2011 and 2012. The bonus for Mr. Keglevic represents the first installment of his signing bonus. As an inducement for entering into his employment agreement, Mr. Campbell was entitled to a one-time payment of $5,092,250 in January 2009. Mr. Walters was paid a signing bonus of $100,000 in March 2008 and Mr. McFarland received a signing bonus of $150,000 in July 2008.

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(3) The amounts reported as “Stock Awards” represent the compensation expense recognized over the vesting period in accordance with SFAS 123R for the restricted stock and/or stock options awarded under the 2007 Stock Incentive Plan. The 2007 Stock Incentive Plan is a stock-based incentive compensation plan providing for stock option awards to designated employees and non-employee directors. The reported amount includes the applicable 2008 compensation cost for restricted stock units, deferred shares or stock options awarded in 2008.

(4) Amounts reported as “Non-Equity Incentive Plan Compensation” were earned by the executive in 2008 and relate to 2008 awards pursuant to the Executive Annual Incentive Plan. Those awards will be paid to the executives in March 2009 and are described in the section entitled “Executive Annual Incentive Plan”.

(5) Amounts reported under “Change in Pension Value and Nonqualified Deferred Compensation Earnings” include the aggregate increase in actuarial value of EFH Corp.’s Retirement Plan and Supplemental Retirement Plan. EFH Corp. and its participating subsidiaries maintain the Retirement Plan, which is qualified under applicable provisions of the Code and covered by ERISA. The Retirement Plan contains both a traditional final average pay component and a cash balance component. Mr. Greene is covered under the traditional final average pay component and Messrs. Campbell and Burke are covered under the cash balance component. While employed by EFH Corp., Mr. Poole was also covered under the cash balance program. For a more detailed description of EFH Corp.’s retirement plans, please refer to the narrative that follows the Pension Benefits table. There are no above market earnings for nonqualified deferred compensation.

(6) Amounts reported as “All Other Compensation” are attributable to the executive officer’s participation in certain EFH Corp. plans and as otherwise described in this footnote.

Under EFH Corp.’s Thrift Plan, all eligible employees of EFH Corp. and any of its participating subsidiaries may contribute a portion of their regular salary or wages to the plan. Under the Thrift Plan, EFH Corp. matches a portion of an employee’s contributions. This matching contribution is 75% of the employee’s contribution up to the first 6% of the employee’s salary for employees covered under the traditional defined benefit component of the Retirement Plan, and 100% of the employee’s contribution up to 6% of the employee’s salary for employees covered under the cash balance component of the Retirement Plan (or those not eligible to participate in the Retirement Plan). All matching contributions are invested in Thrift Plan investments as directed by the participant. The amounts reported under “All Other Compensation” in the Summary Compensation Table include the following matching amounts for Messrs. Young, $8,664; Keglevic, $5,605;Campbell, $4,600; Greene, $10,351; Burke, $13,800; Walters, $12,101; McFarland, $1,875 and Poole, $11,040. All eligible Thrift Plan participants, including the executive officers, became entitled to receive an additional contribution from EFH Corp. as a result of the liquidation of the Leveraged Employee Stock Ownership Plan (LESOP)-the plan that was established to fund future employer matching contributions to the Thrift Plan. As a result, the amounts reported under “All Other Compensation” in the Summary Compensation Table for Messrs. Campbell, Greene, Burke and Poole include a cash allocation of $500, which was paid into each executive officer’s Thrift Plan account in April 2008.

Under EFH Corp.’s Salary Deferral Program, all eligible employees may defer a percentage of their salary and/or annual incentive awards. EFH Corp. matches a portion of the salary deferral. Please refer to the narrative that follows the Nonqualified Deferred Compensation table for a more detailed description of the Salary Deferral Program and the matching formula. Salaries and incentive awards deferred under the Salary Deferral Program are included in amounts reported under Salary and Non-Equity Incentive Plan Compensation in the Summary Compensation Table. Matching awards made in 2008 under the Salary Deferral Program, which are included under “All Other Compensation” in the Summary Compensation Table, include these amounts for Messrs. Young, $66,667; Keglevic, $20,000; Campbell, $0; Greene, $65,000; Burke, $48,000 and Walters, $30,667. Mr. Poole had a matching award of $16,889 that was offset by a forfeiture of $22,090 for a total of ($5,201).

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Under EFH Corp.’s Split-Dollar Life Insurance Program, a split-dollar life insurance policy was purchased for Mr. Greene. The eligibility provisions of this program were modified in 2003 so that no new participants may be added after December 31, 2003. Accordingly, Messrs. Young, Keglevic, Campbell, Burke, Walters, McFarland and Poole were not eligible to participate in the Split-Dollar Life Insurance Program. The death benefits of Mr. Greene’s policy are equal to four times his annual Split-Dollar Life Insurance Program compensation. EFH Corp. pays the premiums for the policies and has received a collateral assignment of the policies equal in value to the sum of all of its insurance premium payments; provided that premium payments made after August 1, 2002, are made on a non-split-dollar life insurance basis and EFH Corp.’s rights under the collateral assignment are limited to premium payments made prior to August 1, 2002. Although the Split-Dollar Life Insurance Program is terminable at any time, it is designed so that if it is continued, EFH Corp. will fully recover all of the insurance premium payments covered by the collateral assignments either upon the death of the participant or, if the assumptions made as to policy yield are realized, upon the later of 15 years of participation or the participant’s attainment of age 65. Because premium payments for Mr. Greene were made on a non-split-dollar life insurance basis during 2008, such premiums were fully taxable to Mr. Greene, and EFH Corp. provided tax gross-up payments to offset the effect of such taxes. During 2008, the amounts reported under “All Other Compensation” in the Summary Compensation Table attributable to the aggregate amount of premiums amounted to $82,320 for Mr. Greene.The amount reported under “All Other Compensation” also includes tax gross-up of $54,477 for Mr. Greene, which was provided to offset the effect of income taxes on premium payments made on a non-split dollar life insurance basis during 2008. In October 2007, the Split-Dollar Life Insurance program was amended to freeze the death benefits at the current level and the vested portions of the policies were fully funded.

Amounts reported under “All Other Compensation” for Messrs. Young, Keglevic and McFarland include payments for moving expenses in the amount of $340,991, $51,053, and $78,557, respectively.

Amounts reported under “All Other Compensation” for Mr. Poole include a severance payment which consists of lump sum cash payments of (i) $982,400, representing the cash severance that would be due to him under his employment agreement upon his termination from EFH Corp. and (ii) $4,155,000, representing the amount agreed to be paid with regard to his ungranted 2008 and 2009 long term performance units under the company’s pre-Merger equity incentive plan and (iii) a one time cash payment of $22,090 equal to the forfeited portion of his account under the Salary Deferral Program. Additionally, Mr. Poole received a tax gross-up for $2,431,885 to offset the excise tax which resulted from the above payments related to the Merger.

Amounts reported under “All Other Compensation” for Messrs Young, Campbell and Burke include amounts for tax gross-up in the amount of $19,282, $59,187 and $558,651, respectively. The gross-up for Mr. Young was related to moving expenses. Messrs. Campbell and Burke received a tax gross-up for payments made in connection with the Merger.

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Amounts reported under “All Other Compensation” also include the perquisites summarized in the following table for our Named Executive Officers.

2008 Perquisites for Named Executive Officers

Name	Financial Planning	Executive Physical	Home Security Expense	Country Club	Board of Directors Strategy Meeting	Other – Spouse Travel (1)	Total
John F. Young	17,620	0	2,325	0	1,598	3,479	25,022
Paul M. Keglevic	0	0	0	0	2,343	6,001	8,344
David A. Campbell	9,730	1,743	0	0	155	0	11,628
M. S. Greene	9,730	0	0	6,354	914	2,979	19,977
James A. Burke	8,530	0	0	4,108	3,325	0	15,963
Robert C. Walters	0	0	0	0	1,481	0	1,481
M. A. McFarland	0	2,775	0	0	3,088	1,430	7,293
David P. Poole	8,540	0	0	518	0	873	9,931

The values reported for perquisites are actual amounts spent by EFH Corp.

(1) Amounts in the “Other” column include spouse’s expense while accompanying executive on business travel.

For a discussion of the terms of the employment agreements with the Named Executive Officers, please see the “Individual Compensation” section.

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The following table sets forth information regarding grants of compensatory awards to our Named Executive Officers during the fiscal year ended December 31, 2008.

Grants of Plan-Based Awards – 2008

Name	Grant Date	Date of Board Action	Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1)			Estimated Future Payouts Under Equity Incentive Plan Awards(2)			All Other Stock Awards: # Shares or Units(3)	All Other Option Awards: # of Securities Underlying Options (#)(4)	Exercise or Base Price of Option Awards ($/sh)		Grant Date Fair Value of Stock Award(5)
			Threshold ($)	Target ($)	Max. ($)	Threshold (#)	Target (#)	(Max) (#)
John F. Young	05/15/08	05/15/08	500,000	1,000,000	2,000,000
	02/01/08	01/30/08					3,750,000			3,750,000	$	5.00	13,635,000
	02/01/08	01/30/08							600,000				3,000,000
Paul M. Keglevic	05/22/08	05/22/08	225,000	450,000	900,000
	12/22/08	05/22/08					1,250,000			1,250,000	$	5.00	6,442,500
	07/01/08	05/22/08							225,000				1,125,000
David A. Campbell	05/15/08	05/15/08	225,000	450,000	900,000
	05/20/08	05/02/08					2,000,000			2,000,000	$	5.00	7,272,000
	05/20/08	05/02/08							500,000				2,500,000
M.S. Greene	05/15/08	05/15/08	243,750	487,500	975,000
	05/20/08	01/30/08					1,000,000			1,000,000	$	5.00	3,636,000
James A. Burke	05/15/08	05/15/08	225,000	450,000	900,000
	05/20/08	01/30/08					1,225,000			1,225,000	$	5.00	4,454,100
Robert C. Walters	05/15/08	05/15/08	215,625	431,250	862,500
	05/20/08	02/29/08					1,000,000			1,000,000	$	5.00	3,636,000
M. A. McFarland	05/22/08	05/22/08	187,500	375,000	750,000
	12/22/08	05/22/08					1,000,000			1,000,000	$	5.00	5,114,000
	07/07/08	05/22/08							100,000				500,000
David P. Poole			N/A	N/A	N/A		N/A		N/A	N/A

(1) The amounts disclosed under the heading “Estimated Possible Payouts under Non-Equity Incentive Plan Awards” reflect the threshold, target and maximum amounts available under the Executive Annual Incentive Plan and each executive’s employment agreement. The actual awards for the 2008 plan year were paid in March 2009 and are reported in the Summary Compensation Table under the heading “Non-Equity Incentive Plan Compensation” and are described under the section entitled “Executive Annual Incentive Plan”.

(2) Represents grants of performance vesting options under the 2007 Stock Incentive Plan. Because there is no market of our common stock, the per share exercise price is the fair market value of one share of our common stock on the grant date as determined in good faith by our Board of Directors. If we achieve specific EBITDA targets, these options are eligible to become vested in installments of 20% on each of December 31, 2008, 2009, 2010, 2011 and 2012. If an EBITDA target for a given fiscal year is not met, these options may still vest on a “catch up” basis if, at the end of fiscal years 2009, 2010, 2011, or 2012, the applicable cumulative EBITDA target is achieved. In addition, these options are subject to certain accelerated vesting provision as described in “Potential Payments upon Termination or Change-in Control” below.

(3) Mr. Young received 600,000 restricted stock units in February 2008 which were fully vested upon grant; however if he voluntarily terminates his employment without good reason (other than due to disability) prior to the February 2010, he will forfeit all of the restricted stock units.

Mr. Keglevic received 225,000 deferred shares in July 2008. The deferred shares will vest and become non-forfeitable as to 112,500 of the shares in July 2011 and 112,500 of the shares in July 2013. In addition, these deferred shares are subject to certain accelerated vesting provision as described in “Potential Payments upon Termination or Change-in Control” below.

In May 2008, Mr. Campbell received a grant of 500,000 deferred shares in connection with his continued employment with EFH Corp. and Luminant. The deferred shares will be issued to Mr. Campbell upon the earlier of (i) his separation of employment for any reason or (ii) the occurrence of a change in control of EFH Corp. or in the ownership of a substantial portion of the assets of EFH Corp.

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In July 2008, Mr. McFarland received a grant of 100,000 deferred shares. These shares will vest in July 2010 if Mr. McFarland is employed by EFH Corp. or upon a change in control of EFH Corp. or upon Mr. McFarland’s termination for good reason, without cause, death or disability.

(4) Represents grants of time-vested, non-qualified stock options under the 2007 Stock Incentive Plan. Because there is no market for our common stock, the per share exercise price is the fair market value of one share of our common stock on the grant date as determined in good faith by our Board of Directors. These options are scheduled to become exercisable ratably in installments of 20% annually. In addition, these options are subject to certain accelerated vesting provisions as described in “Potential Payments upon Termination or Change-in Control” below.

(5) The amounts reported under “Grant Date Fair Value of Stock Award” represent the compensation expense under SFAS 123R for the entire five-year performance period related to the 2008 Awards.

Outstanding Equity Awards at Fiscal Year-End– 2008

	Option Awards					Stock Awards
	# of Securities Underlying Unexercised Options
Name	Exercisable (1)	Unexercisable (2)	Equity Incentive Plan Awards: # of Securities Underlying Unexercised Unearned Options(3)	Option Exercise Price	Option Expiration Date	# of Shares or Units of Stock That Have Not Vested (4)	Market Value of Shares of Units of Stock That Have Not Vested	Equity Incentive Plan Awards: # of Unearned Shares, Units or Other Rights That Have Not Vested	Equity Incentive Plan Awards Market Payout Value of Unearned Shares, Units or Rights That Have Not Vested
John F. Young	1,500,000	3,000,000	3,000,000	5.00	02/01/2018
Paul M. Keglevic	250,000	1,250,000	1,000,000	5.00	12/22/2018	225,000	1,125,000
David A. Campbell	800,000	1,600,000	1,600,000	5.00	05/20/2018
M. S. Greene	700,000	500,000	800,000	5.00	05/20/2018
James A. Burke	490,000	980,000	980,000	5.00	05/20/2018
Robert C. Walters	400,000	800,000	800,000	5.00	05/20/2018
M. A. McFarland	200,000	1,000,000	800,000	5.00	12/22/2018	100,000	500,000
David Poole	NA	NA	NA

(1) Amounts reported for Messrs Young, Keglevic, Campbell, Greene, Burke, Walters and McFarland include 750,000, 250,000, 400,000, 200,000, 245,000, 200,000 and 200,000 options, respectively, that vested in February 2009.

(2) These options are scheduled to become exercisable ratably in October 2009, 2010, 2011 and 2012 for Messrs Young, Campbell, Greene, Burke and Walters and ratably in July 2009, 2010, 2011, 2012 and 2013 for Messrs Keglevic and McFarland.

(3) If we achieve certain performance targets, these options are eligible to become exercisable ratably as of the end of fiscal years 2009, 2010, 2011 and 2012.

(4) The deferred shares for Mr. Keglevic will vest and become nonforfeitable as to (i) 112,500 of the shares on the third anniversary of employment and (ii) 112,500 of the shares on the fifth anniversary of employment.

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The following table sets forth information regarding the vesting of equity awards held by the Named Executive Officers during 2008:

Options Exercised and Stock Vested – 2008

	Option Awards		Stock Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)	Number of Shares Acquired on Vesting (#)	Value Realized on Vesting ($)
John F. Young (1)	0	0	600,000	3,000,000
Paul M. Keglevic	0	0
David A. Campbell(2)	0	0	500,000	2,500,000
M.S. Greene	0	0
James A. Burke	0	0
Robert C. Walters	0	0
M. A. McFarland	0	0
David P. Poole	N/A	N/A	N/A	N/A

(1) Mr. Young vested in the 600,000 restricted stock units that he received in February 2008 however, if he terminates employment voluntarily or is terminated for cause within two years from his date of employment these restricted stock units will be forfeited.

(2) Mr. Campbell entered into a Deferred Share Agreement with EFH Corp. in May 2008. Pursuant to this agreement, EFH Corp. will issue 500,000 shares of common stock to Mr. Campbell on the earlier of (i) Mr. Campbell’s separation of service for any reason and (ii) the later of January 2, 2009 or the occurrence of a change in the ownership or effective control of EFH Corp., or in the ownership of a substantial portion of the assets of EFH Corp.

The following table sets forth information regarding our retirement plans that provide for benefits, in connection with, or following, the retirement of the Named Executive Officers for the fiscal year ended December 31, 2008:

Pension Benefits – 2008

Name	Plan Name	Number of Years Credited Service (#)	PV of Accumulated Benefit ($)	Payments During Last Fiscal Year ($)
John F. Young	Retirement Plan Supplemental Retirement Plan	N/A N/A	N/A N/A	0
Paul M. Keglevic	Retirement Plan Supplemental Retirement Plan	N/A N/A	N/A N/A	0
David A. Campbell (1)	Retirement Plan Supplemental Retirement Plan	3.5833 7.1667	26,379 49,510	0
M.S. Greene	Retirement Plan Supplemental Retirement Plan	38.1667 38.1667	1,327,489 4,301,798	0
James A. Burke	Retirement Plan Supplemental Retirement Plan	3.1667 3.1667	21,287 32,076	0
Robert C. Walters	Retirement Plan Supplemental Retirement Plan	N/A N/A	N/A N/A	0
M. A. McFarland	Retirement Plan Supplemental Retirement Plan	N/A N/A	N/A N/A	0
David P. Poole (2)	Retirement Plan Supplemental Retirement Plan	2.9167 5.8334	28,353 32,135	0

(1) Mr. Campbell’s employment agreement entitles him to additional retirement compensation under the Supplemental Retirement Plan equal to the retirement benefits he would be entitled to if, during each of his first ten years of service with EFH Corp., he was credited with two years of service under the Supplemental Retirement Plan.

(2) Mr. Poole’s employment agreement entitled him to additional retirement compensation under the Supplemental Retirement Plan equal to the retirement benefits he would be entitled to if, during each of his first ten years of service with EFH Corp. he was credited with two years of service under the Supplemental Retirement Plan.

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EFH Corp. and its participating subsidiaries maintain the Retirement Plan, which is intended to be qualified under applicable provisions of the Code and covered by ERISA. The Retirement Plan contains both a traditional defined benefit component and a cash balance component. Only employees hired before January 1, 2002 may participate in the traditional defined benefit component. All new employees hired after January 1, 2002 and before October 1, 2007 are eligible to participate in the cash balance component. In addition, the cash balance component covers employees previously covered under the traditional defined benefit component who elected to convert the actuarial equivalent of their accrued traditional defined benefit to the cash balance component during a special one-time election opportunity in 2002. Participation in EFH Corp.’s Retirement Plan has been limited to employees of all of its businesses (other than Oncor) who were employed by EFH Corp. (or its participating subsidiaries) on or before October 1, 2007. Accordingly, Messrs. Young, Keglevic, Walters and McFarland are not eligible to participate in the Retirement Plan.

Annual retirement benefits under the traditional final average pay benefit component, which applied during 2008 to Mr. Greene is computed as follows: for each year of accredited service up to a total of 40 years, 1.3% of the first $7,800, plus 1.5% of the excess over $7,800, of the participant’s average annual earnings (base salary) during his or her three years of highest earnings. Under the cash balance component, which applied during 2008 to Messrs. Campbell, Burke, and Poole (during his employment with EFH Corp.), hypothetical accounts are established for participants and credited with monthly contribution credits equal to a percentage of the participant’s compensation (3.5%, 4.5%, 5.5% or 6.5% depending on the participant’s combined age and years of accredited service) and interest credits based on the average yield of the 30-year Treasury bond for the 12 months ending November 30 of the prior year. Benefits paid under the traditional final average pay benefit component of the Retirement Plan are not subject to any reduction for Social Security payments but are limited by provisions of the Code.

The Supplemental Retirement Plan provides for the payment of retirement benefits, which would otherwise be limited by the Code or the definition of earnings under the Retirement Plan. The Supplemental Retirement Plan also provides for the payment of retirement compensation that is not otherwise payable under the Retirement Plan that EFH Corp. or its participating subsidiaries are obligated to pay under contractual arrangements. Under the Supplemental Retirement Plan, retirement benefits are calculated in accordance with the same formula used under the Retirement Plan, except that, with respect to calculating the portion of the Supplemental Retirement Plan benefit attributable to service under the traditional final average pay component of the Retirement Plan, earnings also include Executive Annual Incentive Plan awards which are reported under the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. Participation in EFH Corp.’s Supplemental Retirement Plan has been limited to employees of all of its businesses other than Oncor, who were employed by EFH Corp. (or its participating subsidiaries) on or before October 1, 2007. Accordingly, Messrs. Young, Keglevic, Walters and McFarland are not eligible to participate in the Supplemental Retirement Plan.

The table set forth above illustrates present value on December 31, 2008 of each Named Executive Officer’s Retirement Plan benefit and benefits payable under the Supplemental Retirement Plan, based on their years of service and remuneration through December 31, 2008. Benefits accrued under the Supplemental Retirement Plan after December 31, 2004, are subject to Section 409A of the Code. Accordingly, certain provisions of the Supplemental Retirement Plan have been modified in order to comply with the requirements of Section 409A and related guidance.

The present value of accumulated benefit for the Retirement Plan, traditional final average pay component, was calculated based on the executive’s straight life annuity payable at the earliest age that unreduced benefits are available under the plan (generally age 62). Post-retirement mortality was based on the RP2000 Combined Healthy mortality table projected 10 years using scale AA. A discount rate of 6.90% was applied and no pre-retirement mortality or turnover was reflected.

The present value of accumulated benefit for the Retirement Plan, cash balance component, was calculated as the value of their cash balance account projected to age 65 at an assumed growth rate of 4.75% and then discounted back to December 31, 2008 at 6.90%. No mortality or turnover assumptions were applied.

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The following table sets forth information regarding plans that provide for the deferral of the Named Executive Officers’ compensation on a basis that is not tax-qualified for the fiscal year ended December 31, 2008:

Nonqualified Deferred Compensation – 2008 (1)

Name	Executive Contributions in Last FY ($)	Registrant Contributions in Last FY ($) (2)		Aggregate Earnings in Last FY ($)		Aggregate Withdrawals/ Distributions($)(3)		Aggregate Balance at Last FYE ($)
John F. Young	66,667	66,667		(30,679	)	0		102,654
Paul M. Keglevic	20,000	20,000		142		0		40,142
David A. Campbell	0	0		(61,532	)	(15,198,604	)	147,333
M.S. Greene	65,000	65,000		57,529		(8,061,810	)	1,343,190
James A. Burke	48,000	48,000		(84,255	)	(5,401,662	)	171,604
Robert C. Walters	30,667	30,667		(11,016	)	0		50,318
M. A. McFarland	0	0		0		0		0
David P. Poole	56,362	(5,201	)	(23,181	)	(14,931,051	)	0

(1) The amounts reported in the Nonqualified Deferred Compensation table also include deferrals and the company match under the Salary Deferral Program. The amounts reported as “Executive Contributions in Last FY” are also included as “Salary” in the Summary Compensation Table.

Under EFH Corp.’s Salary Deferral Program each employee of EFH Corp. and its participating subsidiaries who is in a designated job level and whose annual salary is equal to or greater than an amount established under the Salary Deferral Program ($110,840 for the program year beginning January 1, 2008) may elect to defer up to 50% of annual base salary, and/or up to 100% of any bonus or incentive award, for a period of seven years, for a period ending with the retirement of such employee, or for a combination thereof. EFH Corp. makes a matching award, subject to forfeiture under certain circumstances, equal to 100% of up to the first 8% of salary deferred under the Salary Deferral Program. Mr. Greene is participating in the Salary Deferral Program under a pre-1998 provision that allows an employee to defer up to 10% of annual base salary for a period of seven years, for a period ending with the retirement of such employee or a combination thereof. EFH Corp. makes a matching award, subject to forfeiture under certain circumstances, up to the maximum of 10% of salary deferred under the Salary Deferral Program for Mr. Greene.

Deferrals are credited with earnings or losses based on the performance of investment alternatives under the Salary Deferral Program selected by each participant. At the end of the applicable maturity period, the trustee for the Salary Deferral Program distributes the deferrals and the applicable earnings in cash as a lump sum or in annual installments at the participant’s election made at the time of deferral. EFH Corp. is financing the retirement option portion of the Salary Deferral Program through the purchase of corporate-owned life insurance on the lives of participants. The proceeds from such insurance are expected to allow EFH Corp. to fully recover the cost of the retirement option.

(2) The amount included in “Registrant Contributions in Last FY” attributable to EFH Corp.’s matching award under the Salary Deferral Program was for Messrs. Young, $66,667; Keglevic, $20,000; Campbell, $0; Greene, $65,000; Burke, $48,000; Walters, $30,667. Mr. Poole had a matching award of $16,889 that was offset by a forfeiture of $22,090 for a total of ($5,201).

(3) Amounts reported under “Aggregate Withdrawals/Distributions” include the following amounts for performance units under EFH Corp.’s pre-Merger equity incentive compensation plan that vested in October 2007, but were deferred and paid in January 2008: Mr. Campbell, $15,198,604; Mr. Greene, $2,960,733; Mr. Burke, $3,151,662 and Mr. Poole, $14,349,364. It also includes the following amounts for the TXU Corp. Deferred and Incentive Compensation Plan paid in January 2008 to Mr. Greene, $2,054,237. These amounts are disclosed under this table because they meet the definition of “nonqualified deferred compensation” under the Code. Also, the amount reported in “Aggregate Withdrawals/Distributions” for Messrs. Greene and Burke include distributions of $3,000,000 and $2,250,000, respectively, that the executives were entitled to receive in respect of outstanding equity awards, but which they agreed to forego, pursuant to the terms of their respective Deferred Share Agreements, in exchange for deferred shares of the post-Merger equity of EFH Corp.These amounts were previously reported under “Registrant Contributions in Last FY”.

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Potential Payments upon Termination or Change in Control

The tables and narrative below provide information for payments to the Named Executive Officers (or, as applicable, enhancements to payments or benefits) in the event of termination including retirement, voluntary, for cause, death, disability, without cause or change in control.

The information in the tables below is presented in accordance with SEC rules, assuming termination of employment and other information as of December 31, 2008.

Employment Arrangements with Contingent Payments:As of December 31, 2008, each of Messrs. Young, Keglevic, Campbell, Greene, Burke, Walters and McFarland had employment agreements with change in control and severance provisions as described in the following tables. Mr. Poole had an employment agreement and the change in control and severance terms included in the employment agreement governed until he left EFH Corp. in March 2008.

Mr. Poole

In March 2008, Mr. Poole resigned from EFH Corp. for “good reason” as defined in his employment agreement. Under the terms of his Severance Agreement, EFH Corp. provided Mr. Poole a severance payment which consisted of a lump sum cash payment of (i) $982,400, representing the cash severance that would be due to him under his employment agreement upon his termination from EFH Corp. plus (ii) $4,155,000, representing the amount agreed to be paid with regard to his ungranted 2008 and 2009 long term performance units under EFH Corp.’s pre-Merger equity incentive compensation plan, plus (iii) a one time cash payment equal to the forfeited portion of his account under the Salary Deferral Program. Additionally, as provided in his employment agreement, Mr. Poole received a tax gross-up in the amount of $2,431,885 to offset the excise taxes that resulted from the severance payment.

1. Mr. Young

Potential Payments to Mr. Young upon Termination (per employment agreement as of December 31, 2008)

Benefit	Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance									$	5,000,000	$	6,000,000
Executive Annual Incentive Plan	$	0	$	0	$	1,000,000	$	1,000,000	$	0	$	0
Vesting of Restricted Stock Units					$	3,000,000	$	3,000,000	$	3,000,000	$	3,000,000
Deferred Compensation
- Salary Deferral Program	$	0	$	0	$	51,327	$	51,327	$	0	$	51,327
Health & Welfare
- Medical/COBRA	$	0	$	0	$	0	$	0	$	29,883	$	29,883
- Dental/COBRA	$	0	$	0	$	0	$	0	$	2,971	$	2,971
Totals	$	0	$	0	$	4,051,327	$	4,051,327	$	8,032,854	$	9,084,181

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Mr. Young has entered into an employment that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. Young’s death or disability:

a. a prorated annual incentive bonus for the year of termination; and

b. payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled.

2. In the event of Mr. Young’s termination without cause or resignation for good reason:

a. a lump sum payment equal to two and one-half times the sum of (i) his annualized base salary and (ii) a prorated annual incentive bonus;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled; and

c. certain continuing health care and company benefits.

3. In the event of Mr. Young’s termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two and one-half times the sum of: (i) his annualized base salary and (ii) his annual bonus target;

b. a prorated annual incentive bonus for the year of termination;

c. payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled;

d. certain continuing health care and company benefits; and

e. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

A change in control is generally defined as (i) a transaction that results in a sale of substantially all of our assets to another person and such person having more seats on our Board than the Sponsor Group, (ii) a transaction that results in a person not in the Sponsor Group owning more than 50% of our common stock and such person having more seats on our Board than the Sponsor Group or (iii) a transaction that results in the Sponsor Group owning less than 20% of our common stock and the Sponsor Group not being able to appoint a majority of the directors to our Board.

Mr. Young’s employment agreement includes customary non-compete and non-solicitation provisions that generally restrict Mr. Young’s ability to compete with us or solicit our customers or employees for his own personal benefit during the term of the employment agreement and 24 months after the employment agreement expires or is terminated.

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2. Mr. Keglevic

Potential Payments to Mr. Keglevic upon Termination (per employment agreement as of December 31, 2008)

Benefit	Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance	$	0	$	0	$	0	$	0	$	2,100,000	$	2,100,000
Executive Annual Incentive Plan	$	0	$	0	$	450,000	$	450,000	$	0	$	0
Vesting of Deferred Shares	$	0	$	0	$	3,200,000	$	3,200,000	$	3,200,000	$	3,200,000
Deferred Compensation
- Salary Deferral Program	$	0	$	0	$	20,071	$	20,071	$	0	$	20,071
Health & Welfare
- Dental/COBRA	$	0	$	0	$	0	$	0	$	2,233	$	2,233
Totals	$	0	$	0	$	3,670,071	$	3,670,071	$	5,302,233	$	5,322,304

Mr. Keglevic entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. Keglevic’s death or disability:

a. a prorated annual incentive bonus for the year of termination; and

b. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled.

2. In the event of Mr. Keglevic’s termination without cause or resignation for good reason:

a. for a termination occurring on or prior to the second anniversary of agreement date a lump sum payment equal to two times the sum of his annualized base salary and annual target bonus and for a termination occurring after the second anniversary of agreement date a lump sum payment equal to (i) two times of his annualized base salary, (ii) a prorated annual incentive bonus and (iii) a lump sum equal to the matching contributions which would have been made on his behalf to EFH Corp.’s Salary Deferral Program had Executive continued his participation in such plan for an additional twelve months;

b. for a termination occurring prior to July 1, 2013, the right (but not the obligation) to sell to EFH Corp. all (but not less than all) of his deferred shares for a purchase price of $3,200,000;

c. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled; and

d. certain continuing health care and company benefits.

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3. In the event of Mr. Keglevic’s termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of: (i) his annualized base salary (ii) his annual bonus target;

b. a prorated annual incentive bonus for the year of termination;

c. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled;

d. certain continuing health care and company benefits; and

e. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

3. Mr. Campbell

Potential Payments to Mr. Campbell upon Termination (per employment agreement as of December 31, 2008)

Benefit	Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance	$	0	$	0	$	0	$	0	$	2,100,000	$	2,100,000
Executive Annual Incentive Plan	$	0	$	0	$	450,000	$	450,000	$	0	$	0
Deferred Shares	$	2,500,000	$	2,500,000	$	2,500,000	$	2,500,000	$	2,500,000	$	2,500,000
Retirement Benefits
- Supplemental Retirement Plan (1)	$	103,497	$	103,497	$	103,497	$	247,029	$	103,497	$	103,497
Deferred Compensation
- Salary Deferral Program (2)	$	70,278	$	70,278	$	70,278	$	70,278	$	70,278	$	70,278
Health & Welfare
- Medical/COBRA	$	0	$	0	$	0	$	0	$	23,997	$	23,997
- Dental/COBRA	$	0	$	0	$	0	$	0	$	2,233	$	2,233
Totals	$	2,673,775	$	2,673,775	$	3,123,775	$	3,267,307	$	4,800,005	$	4,800,005

(1) Mr. Campbell’s employment agreement entitles him to additional retirement compensation under the Supplemental Retirement Plan equal to the retirement benefits he would be entitled to if, during each of his first ten years of service with EFH Corp., he was credited with two years of service under the Supplemental Retirement Plan.

(2) Mr. Campbell is fully vested in the company matching portion of the Salary Deferral Plan

Mr. Campbell entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. Campbell’s death or disability:

a. a prorated annual incentive bonus for the year of termination; and

b. payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled.

2. In the event of Mr. Campbell’s termination without cause or resignation for good reason:

a. a lump sum payment equal to two times the sum of: (i) his annualized base salary and (ii) his annual incentive target;

b. payment of employee benefits, including stock compensations, if any, to which Mr. Campbell may be entitled; and

c. certain continuing health care and company benefits.

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3. In the event of Mr. Campbell’s termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of: (i) his annualized base salary and (ii) his annual bonus target;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled;

c. certain continuing health care and company benefits; and

d. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

4. Mr. Greene

Potential Payments to Mr. Greene upon Termination (per employment agreement as of December 31, 2008)

Benefit	Retirement		Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance	$	0	$	0	$	0	$	0	$	0	$	2,275,000	$	2,275,000
Executive Annual Incentive Plan	$	0	$	0	$	0	$	487,500	$	487,500	$	0	$	0
- Supplemental Retirement Plan(1)	$	4,301,851	$	4,301,851	$	4,301,851	$	3,974,507	$	3,781,904	$	4,301,851	$	4,301,851
- Retiree Medical (2)	$	3,828	$	0	$	0	$	0	$	0	$	0	$	0
Deferred Compensation
- Salary Deferral Program	$	671,595	$	671,595	$	671,595	$	671,595	$	671,595	$	671,595	$	671,595
Health & Welfare
- Medical/COBRA	$	0	$	0	$	0	$	0	$	0	$	15,949	$	15,949
Other
- Split-Dollar Life Insurance (3)	$	136,796	$	0	$	0	$	3,140,000	$	136,796	$	136,796	$	136,796
Totals	$	5,114,070	$	4,973,446	$	4,973,446	$	8,273,602	$	5,077,795	$	7,401,191	$	7,401,191

(1) Mr. Greene is fully vested in all retirement benefits as disclosed in the Pension Benefits table.

(2) Amount reported is the annual subsidy provided by EFH Corp.

(3) Amount reported, other than death benefit, is the yearly premium and tax gross-up. Amount reported in the case of death is the death benefit payable by the insurance provider.

Mr. Greene entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. Greene’s death or disability:

a. a prorated annual incentive bonus for the year of termination; and

b. payment of employee benefits, including stock compensation, restricted stock units or deferred shares, if any, to which Mr. Greene may be entitled.

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2. In the event of Mr. Greene’s termination without cause or resignation for good reason:

a. a lump sum payment equal to two times the sum of: (i) his annualized base salary and (ii) his annual incentive target;

b. payment of employee benefits, including compensation, if any, to which Mr. Greene may be entitled; and

c. certain continuing health care and company benefits.

3. In the event of Mr. Greene’s termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of: (1) his annualized base salary (2) his annual bonus target;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Greene may be entitled;

c. certain continuing health care and company benefits; and

d. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

5. Mr. Burke

Potential Payments to Mr. Burke upon Termination (per employment agreement as of December 31, 2008)

Benefit	Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance	$	0	$	0	$	0	$	0	$	2,100,000	$	2,100,000
Executive Annual Incentive Plan	$	0	$	0	$	450,000	$	450,000	$	0	$	0
Retirement Benefits
- Supplemental Retirement Plan	$	46,159	$	46,159	$	53,036	$	210,706	$	46,159	$	46,159
Deferred Compensation
- Salary Deferral Program	$	44,198	$	44,198	$	85,802	$	85,802	$	44,198	$	85,802
Health & Welfare
- Medical/COBRA	$	0	$	0	$	0	$	0	$	23,906	$	23,906
- Dental/COBRA	$	0	$	0	$	0	$	0	$	2,233	$	2,233
Totals	$	90,357	$	90,357	$	588,838	$	746,508	$	2,216,496	$	2,258,100

Mr. Burke entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. Burke’s death or disability:

a. a prorated annual incentive bonus for the year of termination; and

b. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled.

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2. In the event of Mr. Burke’s termination without cause or resignation for good reason:

a. a lump sum payment equal to two times the sum of: (i) his annualized base salary and (ii) his annual incentive target;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled; and

c. certain continuing health care and company benefits.

3. In the event of Mr. Burke’s termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of: (i) his annualized base salary and (ii) his annual bonus target;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled;

c. certain continuing health care and company benefits; and

d. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

6. Mr. Walters

Potential Payments to Mr. Walters upon Termination (per employment agreement as of December 31, 2008)

Benefit	Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance	$	0	$	0	$	0	$	0	$	2,012,500	$	2,012,500
Executive Annual Incentive Plan	$	0	$	0	$	431,250	$	431,250	$	0	$	0
Deferred Compensation
- Salary Deferral Program	$	0	$	0	$	25,159	$	25,159	$	0	$	25,159
Health & Welfare
- Medical/COBRA	$	0	$	0	$	0	$	0	$	23,906	$	23,906
- Dental/COBRA	$	0	$	0	$	0	$	0	$	2,233	$	2,233
Totals	$	0	$	0	$	456,409	$	456,409	$	2,038,639	$	2,063,798

Mr. Walters entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. Walters’ death or disability:

a. a prorated annual incentive bonus for the year of termination; and

b. payment of employee benefits, including stock compensation, if any, to which Mr. Walters may be entitled.

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2. In the event of Mr. Walters’ termination without cause or resignation for good reason:

a. a lump sum payment equal to two times the sum of: (i) his annualized base salary and (ii) his annual incentive target;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Walters may be entitled; and

c. certain continuing health care and company benefits.

3. In the event of Mr. Walters’ termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of: (i) his annualized base salary and (ii) his annual bonus target;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Walters may be entitled;

c. certain continuing health care and company benefits; and

d. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

7. Mr. McFarland

Potential Payments to Mr. McFarland upon Termination (per employment agreement as of December 31, 2008)

Benefit	Voluntary		For Cause		Death		Disability		Without Cause Or For Good Reason		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance	$	0	$	0	$	0	$	0	$	1,750,000	$	1,750,000
Executive Annual Incentive Plan	$	0	$	0	$	375,000	$	375,000	$	0	$	0
Vesting of Deferred Shares	$	0	$	0	$	500,000	$	500,000	$	500,000	$	500,000
Health & Welfare
- Medical/COBRA	$	0	$	0	$	0	$	0	$	23,906	$	23,906
- Dental/COBRA	$	0	$	0	$	0	$	0	$	2,233	$	2,233
Totals	$	0	$	0	$	875,000	$	875,000	$	2,276,139	$	2,276,139

Mr. McFarland entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. McFarland’s death or disability:

a. a prorated annual incentive bonus for the year of termination; and

b. payment of employee benefits, including stock compensation, if any, to which Mr. McFarland may be entitled.

2. In the event of Mr. McFarland’s termination without cause or resignation for good reason:

a. a lump sum payment equal to two times the sum of: (i) his annualized base salary and (ii) his annual incentive target;

b. payment of employee benefits, including stock compensation, if any, to which Mr. McFarland may be entitled; and

c. certain continuing health care and company benefits.

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3. In the event of Mr. McFarland’s termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of: (i) his annualized base salary and (ii) his annual bonus target;

b. payment of employee benefits, including stock compensation, if any, to which Mr. McFarland may be entitled;

c. certain continuing health care and company benefits; and

d. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

Excise Tax Gross-Ups

Executive Officers Covered by Employment Agreements:Pursuant to their employment agreements, if any of our Named Executive Officers would be subject to the imposition of the excise tax imposed by Section 4999 of the Code, related to the executive’s employment, but the imposition of such tax could be avoided by approval of our shareholders as described in Section 280G(b)(5)(B) of the Code, then such executive may cause EFH Corp. to seek such approval, in which case EFH Corp. will use its reasonable best efforts to cause such approval to be obtained and such executive will cooperate and execute such waivers as may be necessary so that such approval avoids imposition of any excise tax under Section 4999. If such executive fails to cause EFH Corp. to seek such approval or fails to cooperate and execute the waivers necessary in the approval process, such executive shall not be entitled to any gross-up payment for any resulting tax under Section 4999.

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The table below sets forth information regarding the aggregate compensation paid to the members of the board of directors during the fiscal year ended December 31, 2008. Directors who are officers, or former officers, of Energy Future Holdings Corp. do not receive any fees for service as a director. Energy Future Holdings Corp. reimburses some directors for certain reasonable expenses incurred in connection with their services as directors.

Director Compensation

Name	Fees Earned or Paid in Cash ($)	Stock Awards ($)	All Other Compensation ($)	Total ($)
Arcilia C. Acosta (1)(2)	75,000	100,000	n/a	175,000
David Bonderman (3)	n/a	n/a	n/a	n/a
Donald L. Evans (4)	2,000,000	550,000	0	2,550,000
Thomas D. Ferguson (3)(7)	n/a	n/a	n/a	n/a
Frederick M. Goltz (3)	n/a	n/a	n/a	n/a
James R. Huffines (2)(5)(6)	150,000	700,000	225,000	1,075,000
Scott Lebovitz (3)	n/a	n/a	n/a	n/a
Jeffrey Liaw (3)	n/a	n/a	n/a	n/a
Marc S. Lipschultz (3)	n/a	n/a	n/a	n/a
Michael MacDougall (3)	n/a	n/a	n/a	n/a
Lyndon L. Olson, Jr. (2)(5)(6)	150,000	700,000	225,000	1,075,000
Kenneth Pontarelli (3)	n/a	n/a	n/a	n/a
William K. Reilly (2)(6)	150,000	700,000	0	850,000
Jonathan D. Smidt (3)	n/a	n/a	n/a	n/a
John F. Young	n/a	n/a	n/a	n/a
William J. Young (3)(7)	n/a	n/a	n/a	n/a
Kneeland Youngblood (2)	150,000	100,000	0	250,000

(1) Ms. Acosta joined the Board in May 2008.

(2) Ms. Acosta and Messrs. Huffines, Olson, Reilly and Youngblood receive $150,000 annually and an annual equity award valued at $100,000 for their service as a director.

(3) Directors who are employed by a member of the Sponsor Group (or their respective affiliates) do not receive compensation for service as directors.

(4) In May 2008, EFH Corp. entered into a consulting agreement with Mr. Evans, pursuant to which he receives the following compensation:

1. An annual fee of $2,000,000;

2. 200,000 shares of restricted stock, of which 100,000 shares vested during 2008, 75,000 shares at $5.00 per share and 25,000 shares at $7.00 per share; and

3. Options to purchase 600,000 shares of EFH Corp.’s common stock, at an exercise price of $5.00 per share.

The consulting agreement has a term running through October 10, 2009, subject to extension upon mutual agreement of up to three additional years.

(5) In December 2007, EFH Corp. entered into consulting agreements with Messrs. Huffines and Olson with terms of up to five years. As compensation for their consulting services, they receive annual fees of $225,000, which fees are in addition to their standard director compensation arrangements described above. The amounts earned pursuant to these consulting agreements in 2008 are reflected above in the “All Other Compensation” column.

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(6) In 2008, Messrs. Huffines, Olson and Reilly were each granted 120,000 shares of EFH Corp.’s common stock at a price of $5.00 per share.

(7) Mr. Young left the Board in December 2008 and Mr. Ferguson joined the Board in December 2008.

In the second quarter of 2008, Messrs. Evans, Huffines, Olson, Reilly and Youngblood purchased shares of EFH Corp.’s common stock at a price of $5.00 per share. In August 2008, Ms. Acosta purchased shares of EFH Corp.’s common stock at a price of $7.00 per share. In connection with these purchases and with their grants of equity (see footnotes 2 and 6), these directors entered into stockholder agreements and sale participation agreements with EFH Corp. The stockholder agreements create certain rights and restrictions on such equity, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances. Pursuant to the terms of the sale participation agreements, shares of EFH Corp.’s common stock held by these individuals are subject to tag-along and drag-along rights in the event of a sale by the Sponsor Group of shares of EFH Corp.’s common stock held by the Sponsor Group.

Directors and their spouses are invited to attend EFH Corp.’s strategy meeting. As part of the events associated with this meeting, EFH Corp. pays for spousal travel, lodging and meals and for the directors and their spouses to participate in various recreational events and entertainment. For 2008, the aggregate incremental cost to EFH Corp. for such travel, lodging, events and entertainment was less than $10,000 for each director.

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

The following table presents information concerning stock-based compensation plans as of December 31, 2008. (See Note 23 to Financial Statements.)

	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans, excluding securities reflected in column (a)
Equity compensation plans approved by security holders	—	$	—	—
Equity compensation plans not approved by security holders	56,535,286	$	4.65	15,464,714
	56,535,286	$	4.65	15,464,714

Note:	Includes 52.6 million stock options with an exercise price of $5.00 per option.
	Includes 3.9 million vested and unvested restricted shares, deferred shares, as well as stock granted to directors as part of their compensation plan.
	Excluding the 3.9 million awards, the weighted average exercise price of outstanding options, warrants, and rights would be $5.00.

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Beneficial Ownership of Common Stock of Energy Future Holdings Corp.

The following table lists the number of shares of common stock of EFH Corp. beneficially owned by each director and certain current and former executive officers of EFH Corp. and the holders of more than 5% of EFH Corp.’s common stock as of February 25, 2009.

Name	Number of Shares Beneficially Owned	Percent of Class
Texas Energy Future Holdings Limited Partnership (1)	1,657,600,000	98.78	%
Arcilia C. Acosta (2)	70,000	*
David Bonderman (3)	1,657,600,000	98.78	%
Donald L. Evans (4)	700,000	*
Thomas D. Ferguson (5)	1,657,600,000	98.78	%
Frederick M. Goltz (6)	1,657,600,000	98.78	%
James R. Huffines	360,000	*
Scott Lebovitz (5)	1,657,600,000	98.78	%
Jeffrey Liaw (3)	1,657,600,000	98.78	%
Marc S. Lipschultz (6)	1,657,600,000	98.78	%
Michael MacDougall (3)	1,657,600,000	98.78	%
Lyndon L. Olson, Jr.	220,000	*
Kenneth Pontarelli (5)	1,657,600,000	98.78	%
William K. Reilly	200,000	*
Jonathan D. Smidt (6)	1,657,600,000	98.78	%
John F. Young (7)	2,700,000	*
Kneeland Youngblood	140,000	*
Paul M. Keglevic (8)	475,000	*
David A. Campbell (9)	1,300,000	*
M.S. Greene (10)	1,300,000	*
James A. Burke (11)	940,000	*
Robert C. Walters (12)	400,000	*
M.A. McFarland (13)	300,000	*
David P. Poole	—	—
All directors and current executive officers as a group (26 persons)	1,668,401,000	99.2	%

* Less than 1%.

(1) Texas Energy Future Holdings Limited Partnership (“Texas Holdings”) beneficially owns 1,657,600,000 shares of EFH. The sole general partner of Texas Holdings is Texas Energy Future Capital Holdings LLC (“Texas Capital”), which, pursuant to the Amended and Restated Limited Partnership Agreement of Texas Holdings, has the right to vote all of the EFH Corp. shares owned by Texas Holdings. The address of both Texas Holdings and Texas Capital is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.

(2) Shares held in a family limited partnership, ACA Family LP.

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(3) Includes the 1,657,600,000 shares owned by Texas Holdings, over which TPG Partners V, L.P., TPG Partners IV, L.P., TPG FOF V-A, L.P. and TPG FOF V-B, L.P. (the “TPG Entities”) may be deemed, as a result of their ownership of 27.01% of Texas Capital’s outstanding units and certain provisions of Texas Capital’s Amended and Restated Limited Liability Company Agreement (“LLC Agreement”), to have shared voting or dispositive power. The ultimate general partners of the TPG Entities are TPG Advisors IV, Inc. and TPG Advisors V, Inc. David Bonderman and James Coulter are the sole shareholders and directors of TPG Advisors IV Inc. and TPG Advisors V Inc., and therefore, Messrs. Bonderman and Coulter, TPG Advisors IV Inc. and TPG Advisors V Inc. may each be deemed to beneficially own the shares held by the TPG Entities. Messrs. Bonderman, Liaw and MacDougall are managers of Texas Capital. By virtue of their position in relation to Texas Capital and the TPG Entities, Messrs. Bonderman, Liaw and MacDougall may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Liaw and MacDougall disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.

(4) Includes 300,000 shares issuable upon exercise of vested options.

(5) Includes the 1,657,600,000 shares owned by Texas Holdings, over which GS Capital Partners VI Fund, L.P., GSCP VI Offshore TXU Holdings, L.P., GSCP VI Germany TXU Holdings, L.P., GS Capital Partners VI Parallel, L.P., GS Global Infrastructure Partners I, L.P., GS Infrastructure Offshore TXU Holdings, L.P. (GSIP International Fund), GS Institutional Infrastructure Partners I, L.P., Goldman Sachs TXU Investors L.P. and Goldman Sachs TXU Investors Offshore Holdings, L.P. (the “Goldman Entities”) may be deemed, as a result of their ownership of 27.02% of Texas Capital’s outstanding units and certain provision of Texas Capital’s LLC Agreement, to have shared voting or dispositive power. Affiliates of The Goldman Sachs Group, Inc. (“Goldman Sachs”) are the general partner, managing general partner or investment manager of each of the Goldman Entities, and each of the Goldman Entities shares voting and investment power with certain of their respective affiliates. Each of Goldman Sachs and the Goldman Entities disclaims beneficial ownership of such shares of common stock except to the extent of its pecuniary interest therein. Messrs. Ferguson, Lebovitz and Pontarelli are managers of Texas Capital and executives with affiliates of Goldman Sachs. By virtue of their position in relation to Texas Capital and the Goldman Entities, Messrs. Ferguson, Lebovitz and Pontarelli may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Ferguson, Lebovitz and Pontarelli disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is c/o Goldman, Sachs & Co., 85 Broad Street, New York, New York 10004.

(6) Includes the 1,657,600,000 shares owned by Texas Holdings, over which KKR 2006 Fund L.P., KKR PEI Investments, L.P., KKR Partners III, L.P., KKR North American Co-Invest Fund I L.P. and TEF TFO Co-Invest, LP (the “KKR Entities”) may be deemed, as a result of their ownership of 37.05% of Texas Capital’s outstanding units and certain provision of Texas Capital’s LLC Agreement, to have shared voting or dispositive power. The KKR Entities disclaim beneficial ownership of any shares of our common stock in which they do not have a pecuniary interest. Messrs. Goltz, Lipschultz and Smidt are managers of Texas Capital and executives of Kohlberg Kravis Roberts & Co. L.P. By virtue of their position in relation to Texas Capital and the KKR Entities, Messrs. Goltz, Lipschultz and Smidt may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Goltz, Lipschultz and Smidt disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57^th Street, Suite 4200, New York, New York 10019.

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(7) Includes 1,500,000 shares issuable upon exercise of vested options. Also includes 600,000 restricted stock units that fully vested on the date of Mr. Young’s employment and which are payable in shares of EFH Corp. common stock on the second anniversary of the grant date unless Mr. Young terminates his employment without good reason prior to that anniversary, in which case the restricted stock units would be forfeited.

(8) Includes 225,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 250,000 shares issuable upon exercise of vested options.

(9) Includes 500,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 800,000 shares issuable upon exercise of vested options.

(10) Includes 600,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 700,000 shares issuable upon exercise of vested options.

(11) Includes 450,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 490,000 shares issuable upon exercise of vested options.

(12) Includes 400,000 shares issuable upon exercise of vested options.

(13) Includes 100,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 200,000 shares issuable upon exercise of vested options.

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

Policies and Procedures Relating to Related Party Transactions

The Board has adopted a policy regarding related person transactions. Under this policy, a related person transaction shall be consummated or shall continue only if:

1. the Audit Committee of the Board approves or ratifies such transaction in accordance with the policy and if the transaction is on terms comparable to those that could be obtained in arm’s length dealings with an unrelated third party;

2. the transaction is approved by the disinterested members of the Board or the Executive Committee; or

3. the transaction involves compensation approved by the Organization and Compensation Committee of the Board.

For purposes of this policy, the term “related person” includes EFH Corp.’s directors, executive officers, 5% shareholders and their immediate family members. “Immediate family members” means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law or any person (other than a tenant or employee) sharing the household of a director, executive officer or 5% shareholder.

A “related person transaction” is a transaction between EFH Corp. or its subsidiaries and a related person, other than the types of transactions described below, which are deemed to be pre-approved by the Audit Committee of the Board:

1. any compensation paid to a director if the compensation is required to be reported under Item 402 of Regulation S-K of the Securities Act;

2. any transaction with another company at which a related person’s only relationship is as an employee (other than an executive officer), director or beneficial owner of less than 10% of that company’s ownership interests;

3. any charitable contribution, grant or endowment by EFH Corp. to a charitable organization, foundation or university at which a related person’s only relationship is as an employee (other than an executive officer) or director;

4. transactions where the related person’s interest arises solely from the ownership of EFH Corp.’s equity securities and all holders of that class of equity securities received the same benefit on a pro rata basis;

5. transactions involving a related party where the rates or charges involved are determined by competitive bids;

6. any transaction with a related party involving the rendering of services as a common or contract carrier, or public utility, as rates or charges fixed in conformity with law or governmental authority;

7. any transaction with a related party involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture, or similar service;

8. transactions available to all employees or customers generally (unless required to be disclosed under Item 404 of Regulation S-K of the Securities Act, if applicable);

9. transactions involving less than $100,000 when aggregated with all similar transactions;

10. transactions between the Company and its subsidiaries or between subsidiaries of the Company;

11. transactions not required to be disclosed under Item 404; and

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12. open market purchases of the Company’s or its subsidiaries’ debt or equity securities and interest payments on such debt.

The Board has determined that it is appropriate for the Audit Committee of the Board to review and approve or ratify related person transactions. Accordingly, at least annually, management reviews related person transactions to be entered into by EFH Corp. or its subsidiaries, if any. After review, the Audit Committee of the Board approves/ratifies or disapproves such transactions. Management updates the Audit Committee of the Board as to any material changes to such related person transactions. In unusual circumstances, EFH Corp. or its subsidiaries may enter into related person transactions in advance of receiving approval, provided that such related person transactions are reviewed and ratified as soon as reasonably practicable by the Audit Committee of the Board. If the Audit Committee of the Board determines not to ratify such transactions, EFH Corp. shall make all reasonable efforts to cancel or otherwise terminate such transactions.

The related person transactions described below under the heading “Business Affiliations,” were ratified by the Audit Committee of the Board pursuant to the policy described above. All other related person transactions were approved prior to the Board’s adoption of this policy, but were approved by either the Board or its Executive Committee. Transactions described below under “Transactions With Sponsor Affiliates” are not related person transactions under the EFH Corp. policy because they are not with a director, executive officer, 5% shareholder or any of their immediate family members, but are described in the interest of greater disclosure.

Related Person Transactions

Limited Partnership Agreement of Texas Energy Future Holdings Limited Partnership; Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC

The Sponsor Group and certain investors who agreed to co-invest with the Sponsor Group or through a vehicle jointly controlled by the Sponsor Group to provide equity financing for the merger (“Co-Investors”), entered into (i) a limited partnership agreement (the “LP Agreement”) in respect of EFH Corp.’s parent company, Texas Holdings and (ii) the LLC Agreement in respect of Texas Holdings’ sole general partner, Texas Capital. The LP Agreement provides that Texas Capital has the right to vote or execute consents with respect to any shares of EFH Corp.’s common stock owned by Texas Holdings. The LLC Agreement and LP Agreement contain agreements among the parties with respect to the election of EFH Corp.’s directors, restrictions on the issuance or transfer of interests in EFH Corp., including tag-along rights and drag-along rights, and other corporate governance provisions (including the right to approve various corporate actions).

The LLC Agreement provides that Texas Capital and its members will take all action required to ensure that the managers of Texas Capital are also members of EFH Corp.’s Board of Directors. Pursuant to the LLC Agreement each of (i) KKR 2006 Fund L.P. and affiliated investment funds, (ii) TPG Partners V, L.P. and affiliated investment funds and (iii) certain funds affiliated with Goldman Sachs, has the right to designate three managers of Texas Capital. These rights are subject to maintenance of certain investment levels in Texas Holdings.

Registration Rights Agreement

The Sponsor Group and the Co-Investors entered into a registration rights agreement with EFH Corp. upon completion of the Merger. Pursuant to this agreement, in certain circumstances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.’s common stock owned directly or indirectly by them under the Securities Act. In certain circumstances, the Sponsor Group and the Co-Investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.’s common stock under the Securities Act that it may undertake. In January 2008, John Young became a party to this agreement. In 2008, Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and Messrs. Greene, Campbell, Walters, McCall, Burke, Keglevic and McFarland, each of whom are executive officers of EFH Corp., became parties to this agreement.

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Management Services Agreement

In October 2007, in connection with the Merger, the Sponsor Group and Lehman Brothers Inc. entered into a management agreement with EFH Corp. (the “Management Agreement”), pursuant to which affiliates of the Sponsor Group will provide management, consulting, financial and other advisory services to EFH Corp. Pursuant to the Management Agreement, affiliates of the Sponsor Group are entitled to receive an aggregate annual management fee of $35 million, which amount will increase 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of EFH Corp. or in connection with an initial public offering of EFH Corp. or if the parties thereto mutually agree to terminate the Management Agreement. Pursuant to the Management Agreement, affiliates of the Sponsor Group and Lehman Brothers Inc. were paid transaction fees of $300 million for certain services provided in connection with the Merger and related transactions. In addition, the Management Agreement provides that the Sponsor Group will be entitled to receive a fee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition, merger combination and change of control transactions, as well as a termination fee based on the net present value of future payment obligations under the Management Agreement in the event of an initial public offering or under certain other circumstances. Under terms of the Management Agreement, EFH Corp. paid $35 million, inclusive of expenses, to the Sponsor Group during 2008.

Indemnification Agreement

Concurrently with entering into the Management Agreement, the Sponsor Group, Texas Holdings and EFH Corp. entered into an indemnification agreement (the “Indemnification Agreement”), pursuant to which EFH Corp. and Texas Holdings agree to indemnify the Sponsor Group and their affiliates against any claims relating to (i) certain securities and financing transactions relating to the Merger, (ii) the performance of transaction services pursuant to the Management Agreement, (iii) actions or failures to act by EFH Corp., Texas Holdings, Texas Capital or their subsidiaries or affiliates (collectively, the “Company Group”), (iv) service as an officer or director of, or at the request of, any member of the Company Group, and (v) any breach or alleged breach of fiduciary duty as a director or officer of any member of the Company Group.

Sale Participation Agreement

Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and each of our executive officers have entered into sale participation agreements with EFH Corp. Pursuant to the terms of these agreements, among other things, shares of EFH Corp.’s common stock held by these individuals are subject to tag-along and drag-along rights in the event of a sale by the Sponsor Group of shares of EFH Corp.’s common stock held by the Sponsor Group.

Certain Charter Provisions

EFH Corp.’s restated certificate of formation contains provisions limiting directors’ obligations in respect of corporate opportunities.

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Management Stockholders’ Agreement

Subject to a management stockholders’ agreement, certain members of management, including EFH Corp.’s executive officers, along with other members of management, elected to invest in EFH Corp. by contributing cash or common stock, or a combination of both, to EFH Corp. prior to or following the Merger and receiving common stock in EFH Corp. in exchange therefore. The net aggregate amount of this investment as of December 31, 2008 is approximately $44.8 million. The management stockholders’ agreement creates certain rights and restrictions on these shares of common stock, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.

Director Stockholders’ Agreement

In the second and third quarters of 2008, certain members of our Board entered into a stockholders’ agreement with EFH Corp. See “Director Compensation.”

Business Affiliations

Mr. Olson, a member of our board, has an ownership interest in two companies with which Oncor does business. These companies are Texas Meter and Device Company (“TMD”) and Metrum Technologies LLC (“Metrum”). Mr. Olson and his brother collectively directly own approximately 24% of TMD and indirectly own approximately 19% of Metrum. Both entities are majority owned by their chief executive officer. In 2008, Oncor paid TMD approximately $0.9 million and paid Metrum approximately $2.0 million. TMD tests Oncor’s high voltage personal protective equipment. Metrum provides Oncor with cellular-based wireless communications equipment for its meters. Oncor is Metrum’s largest customer. The business relationships with both TMD and Metrum commenced several years prior to Mr. Olson joining EFH Corp.’s Board.

Transactions with Sponsor Affiliates

At the closing of the Merger, TCEH entered into the TCEH Senior Secured Facilities and Oncor entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners. These transactions were approved by the Board of Directors.

Affiliates of GS Capital Partners have from time to time engaged in commercial banking and financial advisory transactions with EFH Corp. in the normal course of business. Affiliates of Goldman Sachs & Co. are party to certain commodity and interest rate hedging transactions with EFH Corp. in the normal course of business.

From time to time affiliates of the Sponsor Group may acquire debt or debt securities issued by EFH Corp. in open market transactions or through loan syndications.

Director Independence

Though not formally considered by the Board of Directors because EFH Corp.’s common stock is not currently registered with the SEC or traded on any national securities exchange, based upon the listing standards of the New York Stock Exchange, the national securities exchange upon which EFH Corp.’s common stock was traded prior to the Merger, only Ms. Acosta and Mr. Youngblood would be considered independent. Because of their relationships with the Sponsor Group or with EFH Corp. directly, none of the other directors would be considered independent. See “Certain Relationships and Related Party Transactions” and “Director Compensation.” Accordingly, we believe that Mr. Youngblood is the only member of the Audit Committee who would meet the independence requirements. EFH Corp. believes that Ms. Acosta is the only member of the Organization and Compensation Committee who would meet the New York Stock Exchange’s independence requirements. EFH Corp. believes that none of the members of EFH Corp.’s Governance and Public Affairs Committee would meet the New York Stock Exchange’s independence requirements.

279

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

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

The Audit Committee of the EFH Corp. Board of Directors has adopted a policy relating to the engagement of EFH Corp.’s independent auditor. The policy provides that in addition to the audit of the financial statements, related quarterly reviews and other audit services, and providing services necessary to complete SEC filings, EFH Corp.’s independent auditor may be engaged to provide non-audit services as described herein. Prior to engagement, all services to be rendered by the independent auditor must be authorized by the Audit Committee in accordance with 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 2008 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 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.

280

The policy prohibits EFH Corp. from engaging its independent auditor to provide:

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

2. Financial information systems design and implementation services;

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

4. Actuarial services;

5. Internal audit outsourcing services;

6. Management or human resource functions;

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

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

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

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

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 internal audit executive. Reports from Deloitte & Touche and the chief internal audit executive describing the services provided by the firm and fees for such services are provided to the Audit Committee no less often than quarterly.

For the years ended December 31, 2008 and 2007, fees billed to EFH Corp. by Deloitte & Touche were as follows:

	2008		2007 (a)
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	$	7,956,000	$	7,237,000
Audit-Related Fees.Fees for services including employee benefit plan audits, due diligence related to mergers, acquisitions and divestitures, accounting consultations and audits in connection with acquisitions, internal control reviews, attest services that are not required by statute or regulation, and consultation concerning financial accounting and reporting standards		4,923,000		5,804,000
Tax Fees.Fees for tax compliance, tax planning, and tax advice related to mergers and acquisitions, divestitures, and communications with and requests for rulings from taxing authorities		1,777,000		1,043,000
All Other Fees.Fees for services including process improvement reviews, forensic accounting reviews, litigation and rate case assistance, and training services		0		80,000
Total	$	14,656,000	$	14,164,000

(a) Audit fees for 2007 increased $675,000 from the amount in the 2007 Form 10-K for payments made in 2008 related to 2007 audits.

281

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Exhibits:

EFH Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2008

Exhibits	Previously Filed* With File Number	As Exhibit
(2)	Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
2(a)	1-12833 Form 8-K (filed February 26, 2007)	2.1	—	Agreement and Plan of Merger, dated February 25, 2007, by and among Energy Future Holdings Corp. (formerly known as TXU Corp.), Texas Energy Future Holdings Limited Partnership and Texas Energy Future Merger Sub Corp
(3(i))	Articles of Incorporation
3(a)	1-12833 Form 8-K (filed October 11, 2007)	3.1	—	Restated Certificate of Formation of Energy Future Holdings Corp., dated October 10, 2007
(3(ii))	By-laws
3(b)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	3(a)	—	Amended and Restated Bylaws of Energy Future Holdings Corp.
(4)	Instruments Defining the Rights of Security Holders, Including Indentures**
	Energy Future Holdings Corp.
4(a)	1-12833 Form 10-K (1997) (filed March 27, 1998)	4(c)	—	Indenture (For Unsecured Debt Securities Series P), dated as of November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon (formerly known as The Bank of New York). Energy Future Holdings Corp.’s Indentures for its Series Q and R Senior Notes are not being filed as they are substantially similar to this Indenture
4(b)	1-12833 Form 10-K (2004) (filed March 16, 2005)	4(q)	—	Officers’ Certificate, dated November 26, 2004, establishing the terms of Energy Future Holdings Corp.’s 5.55% Series P Senior Notes due November 15, 2014

282

Exhibits	Previously Filed* With File Number	As Exhibit
4(c)	1-12833 Form 10-K (2004) (filed March 16, 2005)	4(r)	—	Officers’ Certificate, dated November 26, 2004, establishing the terms of Energy Future Holdings Corp.’s 6.50% Series Q Senior Notes due November 15, 2024
4(d)	1-12833 Form 10-K (2004) (filed March 16, 2005)	4(s)	—	Officers’ Certificate, dated November 26, 2004, establishing the terms of Energy Future Holdings Corp.’s 6.55% Series R Senior Notes due November 15, 2034
4(e)	1-12833 Form 8-K (filed October 31, 2007)	4.1	—	Indenture, dated as of October 31, 2007, relating to Energy Future Holdings Corp.’s 10.875% Senior Notes due 2017 and 11.250%/12.000% Senior Toggle Notes due 2017
	Oncor Electric Delivery Company LLC
4(f)	333-100240 Form S-4 (filed October 2, 2002)	4(a)	—	Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC (formerly Oncor Electric Delivery Company, formerly known as TXU Electric Delivery Company) and The Bank of New York Mellon, as Trustee
4(g)	1-12833 Form 8-K (filed October 31, 2005)	10.1	—	Supplemental Indenture No. 1, dated October 25, 2005, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon
4(h)	333-100240 Form S-4 (filed October 2, 2002)	4(b)	—	Officer’s Certificate, dated May 6, 2002, establishing the terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes (formerly Senior Secured Notes) due 2012 and 7.000% Senior Notes (formerly Senior Secured Notes) due 2032
4(i)	333-106894 Form S-4 (filed July 9, 2003)	4(c)	—	Officer’s Certificate, dated December 20, 2002, establishing the terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes (formerly Senior Secured Notes) due 2015 and 7.250% Senior Notes (formerly Senior Secured Notes) due 2033
4(j)	333-100242 Form S-4 (filed October 2, 2002)	4(a)	—	Indenture (for Unsecured Debt Securities), dated as of August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon, as Trustee
4(k)	333-100242 Form S-4 (filed October 2, 2002)	4(b)	—	Officer’s Certificate, dated August 30, 2002, establishing the terms of Oncor Electric Delivery Company LLC’s 7.00% Debentures due 2022
4(l)	333-100242 Form 8-K (filed September 9, 2008)	4.1	—	Officer’s Certificate, dated September 8, 2008, establishing the terms of Oncor’s 5.95% Senior Secured Notes due 2013, 6.80% Senior Secured Notes due 2018 and 7.50% Senior Secured Notes due 2038

283

Exhibits	Previously Filed* With File Number	As Exhibit
4(m)	333-100242 Form 8-K (filed September 9, 2008)	4.2	—	Registration Rights Agreement, dated September 8, 2008, among Oncor and the representatives of the several initial purchasers of Oncor’s 5.95% Senior Secured Notes due 2013, 6.80% Senior Secured Notes due 2018 and 7.50% Senior Secured Notes due 2038
	Texas Competitive Electric Holdings Company LLC
4(n)	333-108876 Form 8-K (filed October 31, 2007)	4.2	—	Indenture, dated as of October 31, 2007, relating to Texas Competitive Electric Holdings Company LLC’s and TCEH Finance, Inc.’s 10.25% Senior Notes due 2015
4(o)	1-12833 Form 8-K (filed December 12, 2007)	4.1	—	First Supplemental Indenture, dated as of December 6, 2007, to Indenture, dated as of 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
(10)	Material Contracts
	Management Contracts; Compensatory Plans, Contracts and Arrangements
10(a)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(a)	—	2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates
10(b)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(b)	—	Registration Rights Agreement by and among Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp. and the stockholders party thereto
10(c)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(c)	—	Summary of Consulting Arrangement, between Donald Evans and Energy Future Holdings Corp.
10(d)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(d)	—	Consulting Agreement, dated December 5, 2007, between James R. Huffines and Energy Future Holdings Corp.
10(e)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(e)	—	Consulting Agreement, dated December 5, 2007, between Lyndon Olson and Energy Future Holdings Corp.
10(f)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(f)	—	Energy Future Holdings Corp. Non-employee Director Compensation Arrangements

284

Exhibits	Previously Filed* With File Number	As Exhibit
10(g)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(a)	—	Form of Stockholder’s Agreement (for Directors), by and among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and the stockholder party thereto
10(h)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(b)	—	Form of Sale Participation Agreement (for Directors), by and between Texas Energy Future Holdings Limited Partnership and the stockholder party hereto
10(i)			—	EFH Executive Annual Incentive Plan, as amended and restated, effective as of January 1, 2008
10(j)	333-153529 Amendment No. 2 to Form S-4 (filed December 23, 2008)	10(l)	—	EFH Salary Deferral Program, as amended and restated, effective October 10, 2007
10(k)	1-12833 Form 8-K (filed May 23, 2005)	10.7	—	Energy Future Holdings Corp. 2005 Executive Severance Plan
10(l)	333-153529 Amendment No. 2 to Form S-4 (filed December 23, 2008)	10(n)	—	Amendment to the Energy Future Holdings Corp. 2005 Executive Severance Plan and Summary Description
10(m)	1-12833 Form 8-K (filed May 23, 2005)	10.6	—	Energy Future Holdings Corp. Executive Change in Control Policy
10(n)	333-153529 Amendment No. 2 to Form S-4 (filed December 23, 2008)	10(p)	—	Amendment to the Energy Future Holdings Corp. Executive Change in Control Policy
10(o)	1-12833 Form 10-K (2005) (filed March 6, 2006)	10(gg)	—	EFH Split Dollar Life Insurance Program, as amended and restated, executed March 2, 2006, effective as of May 20, 2005
10(p)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(n)	—	Amendment to the EFH Split Dollar Life Insurance Program, effective as of October 10, 2007

285

Exhibits	Previously Filed* With File Number	As Exhibit
10(q)			—	EFH Second Supplemental Retirement Plan, as amended and restated, effective as of October 10, 2007
10(r)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(p)	—	Employment Agreement, dated January 6, 2008, by and between John F. Young and Energy Future Holdings Corp.
10(s)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(e)	—	Form of Non-Qualified Stock Option Agreement (For Executive Officers)
10(t)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(q)	—	Energy Future Holdings Corp. Key Employee Non-Qualified Stock Option Agreement, dated as of February 1, 2008, by and between John F. Young and Energy Future Holdings Corp.
10(u)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(f)	—	Form of Management Stockholder’s Agreement (For Executive Officers)
10(v)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(r)	—	Management Stockholder’s Agreement, dated as of February 1, 2008, by and among John F. Young, Texas Energy Future Holdings Limited Partnership and Energy Future Holdings Corp.
10(w)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(g)	—	Form of Sale Participation Agreement (For Executive Officers)
10(x)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(s)	—	Sale Participation Agreement, dated as of February 1, 2008, by and between John F. Young and Texas Energy Future Holdings Limited Partnership
10(y)			—	Amended and Restated Employment Agreement, dated as of July 1, 2008, by and between Paul M. Keglevic and Energy Future Holdings Corp.
10(z)	1-12833 Form 10-K (2004) (filed March 16, 2005)	10(l)	—	Employment Agreement, dated May 9, 2008, by and among David Campbell, Energy Future Holdings Corp. and Luminant Holding Company LLC

286

Exhibits	Previously Filed* With File Number	As Exhibit
10(aa)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(y)	—	Additional Payment Agreement, dated October 10, 2007, by and among David Campbell, Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and Texas Competitive Electric Holdings Company LLC
10(bb)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(i)	—	Employment Agreement, dated May 9, 2008, by and among Michael Greene, Energy Future Holdings Corp. and Luminant Holding Company LLC
10(cc)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(h)	—	Employment Agreement, dated May 9, 2008, by and between Rob Walters and Energy Future Holdings Corp.
10(dd)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(bb)	—	Severance and Release Agreement, dated March 31, 2008, by and between David P. Poole and Energy Future Holdings Corp.
10(ee)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(p)	—	Amended and Restated Employment Agreement, dated May 9, 2008, by and among James Burke, Energy Future Holdings Corp. and TXU Energy Retail Company LLC
10(ff)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ff)	—	Additional Payment Agreement, dated October 10, 2007, by and among James Burke, Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and Texas Competitive Electric Holdings Company LLC
10(gg)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(k)	—	Employment Agreement, dated May 9, 2008, by and among Charles R. Enze, Energy Future Holdings Corp. and Luminant Holding Company LLC
10(hh)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(a)	—	Employment Agreement, dated May 23, 2008, by and between M. Rizwan Chand and Energy Future Holdings Corp.
10(ii)			—	Amended and Restated Employment Agreement, dated July 7, 2008, by and between Luminant Holding Company LLC, Energy Future Holdings Corp. and Mark Allen McFarland

287

Exhibits	Previously Filed* With File Number	As Exhibit
10(jj)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(nn)	—	Deferred Share Agreement, dated October 9, 2007, by and between James Burke and Texas Energy Future Holdings Limited Partnership
10(kk)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(oo)	—	Deferred Share Agreement, dated October 9, 2007, by and between Charles Enze and Texas Energy Future Holdings Limited Partnership
10(ll)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(qq)	—	Deferred Share Agreement, dated October 9, 2007, by and between Michael Greene and Texas Energy Future Holdings Limited Partnership
10(mm)			—	Employment Arrangement between Mike Blevins and Luminant Holding Company LLC
	Credit Agreements
10(nn)	1-12833 Form 10-Q (Quarter ended September 30, 2007) (filed November 14, 2007)	10.C	—	$24,500,000,000 Credit Agreement, dated as of 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, J. Aron & Company, as posting calculation agent, JPMorgan Chase Bank, N.A., as syndication agent and revolving letter of credit issuer, Credit Suisse, Goldman Sachs Credit Partners L.P., Lehman Commercial Paper Inc. and Morgan Stanley Senior Funding, Inc., as co-documentation agents, 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, and Goldman Sachs Credit Partners L.P., as posting lead arranger and bookrunner
10(oo)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ss)	—	Guarantee Agreement, dated as of 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
10(pp)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(tt)	—	Pledge Agreement, dated as of October 10, 2007, 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 of the secured parties under the $24,500,000,000 Credit Agreement

288

Exhibits	Previously Filed* With File Number	As Exhibit
10(qq)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(uu)	—	Security Agreement, dated as of October 10, 2007, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary grantors party thereto, and Citibank, N.A., as collateral agent for the benefit of the secured parties under the $24,500,000,000 Credit Agreement
10(rr)	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(ss)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ww)	—	Collateral Agency and Intercreditor Agreement, dated as of October 10, 2007, 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, Lehman Brothers Commodity Services Inc., J. Aron & Company, Morgan Stanley Capital Group Inc., Citigroup energy Inc., and each other secured commodity hedge counterparty from time to time party thereto, and any other person that becomes a secured party pursuant thereto
10(tt)	333-100240 Form 10-Q (Quarter ended September 30, 2007) (filed November 14, 2007)	10.A	—	$2,000,000,000 Revolving Credit Agreement, dated as of October 10, 2007, among Oncor Electric Delivery Company LLC, as the borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as administrative agent, fronting bank and swingline lender, Citibank, N.A., as syndication agent and fronting bank, Credit Suisse, Cayman Islands Branch, Goldman Sachs Credit Partners L.P., Lehman Commercial Paper Inc., Morgan Stanley Senior Funding, Inc. as co-documentation agents, J.P. Morgan Securities Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Goldman Sachs Credit Partners L.P., Lehman Brothers Inc. and Morgan Stanley Senior Funding, Inc. as joint lead arrangers and bookrunners
	Other Material Contracts
10(uu)	1-12833 Form 10-Q (Quarter ended June 30, 2004) (filed August 6, 2004)	10(l)	—	Master Framework Agreement, dated May 17, 2004, by and between Oncor Electric Delivery Company LLC and CapGemini Energy LP
10(vv)	1-12833 Form 10-Q (Quarter ended June 30, 2004) (filed August 6, 2004)	10(m)	—	Master Framework Agreement, dated May 17, 2004, by and between Texas Competitive Electric Holdings Company LLC and CapGemini Energy LP

289

Exhibits	Previously Filed* With File Number	As Exhibit
10(ww)	333-100240 Form 8-K (filed August 13, 2008)	10.1	—	Contribution and Subscription Agreement, dated as of August 12, 2008, by and between Oncor and Texas Transmission Investment LLC
10(xx)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(eee)	—	Stipulation as approved by the PUC in Docket No. 34077
10(yy)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(fff)	—	Amendment to Stipulation Regarding Section 1, Paragraph 35 and Exhibit B in Docket No. 34077
10(zz)	1-12833 Form 10-K (2005) (filed March 6, 2006)	10(ss)	—	Extension and Modification of Settlement Agreement executed on January 27, 2006, by and among Oncor Electric Delivery Company LLC and Steering Committee of cities served by Oncor Electric Delivery Company LLC, on behalf of the cities listed therein
10(aaa)	1-12833 Form 10-K (2005) (filed March 6, 2006)	10(tt)	—	Agreement to Resolve Outstanding Franchise Issues executed on January 27, 2006, by and among Oncor Electric Delivery Company LLC and Steering Committee of cities served by Oncor Electric Delivery Company LLC, on behalf of the cities listed therein
10(bbb)	1-12833 Form 10-K (2003) (filed March 15, 2004)	10(qq)	—	Lease Agreement, dated as of February 14, 2002, between State Street Bank and Trust Company of Connecticut, National Association, as owner trustee of ZSF/Dallas Tower Trust, a Delaware grantor trust, as Lessor and EFH Properties Company, a Texas corporation, as Lessee (Energy Plaza Property)
10(ccc)	1-12833 Form 10-Q (Quarter ended June 30, 2007) (filed August 9, 2007)	10.1	—	First Amendment to Lease Agreement, dated as of June 1, 2007, between U.S. Bank, N.A. (as successor-in-interest to State Street Bank and Trust Company of Connecticut, National Association), as owner trustee of ZSF/Dallas Tower Trust, a Delaware grantor trust, as Lessor, and EFH Properties Company, a Texas corporation, as Lessee (Energy Plaza Property)
10(ddd)	1-12833 Form 10-Q (Quarter ended June 30, 2007) (filed August 9, 2007)	10.2	—	Amended and Restated Engineering, Procurement and Construction Agreement, dated as of June 8, 2007, between Oak Grove Management Company LLC, a Delaware limited liability company and a wholly-owned, direct subsidiary of Texas Competitive Holdings Company LLC, and Fluor Enterprises, Inc., a California corporation (confidential treatment has been requested for portions of this exhibit)

290

Exhibits	Previously Filed* With File Number	As Exhibit
10(eee)	1-12833 Form 10-Q (Quarter ended September 30, 2007) (filed November 14, 2007)	10.B	—	Engineering, Procurement and Construction Agreement, dated as of May 26, 2006, between Texas Competitive Electric Holdings Company LLC (as successor-in-interest to EFC Holdings) and Bechtel Power Corporation (confidential treatment has been requested for portions of this exhibit)
10(fff)	1-12833 Form 10-K (2006) (filed March 2, 2007)	10(iii)	—	Amended and Restated Transaction Confirmation by Generation Development Company LLC (formerly known as TXU 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(ggg)	1-12833 Form 10-K (2006) (filed March 2, 2007)	10(jjj)	—	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(hhh)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(sss)	—	ISDA Master Agreement, dated as of October 25, 2007, between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(iii)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ttt)	—	Schedule to the ISDA Master Agreement, dated as of October 25, 2007, between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(jjj)	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(kkk)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(vvv)	—	ISDA Master Agreement, dated as of October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International
10(lll)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(www)	—	Schedule to the ISDA Master Agreement, dated as of October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International
10(mmm)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(xxx)	—	Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Credit Suisse International
10(nnn)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(yyy)	—	Management Agreement, dated as of October 10, 2007, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership, Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P., Goldman, Sachs & Co. and Lehman Brothers Inc.

291

Exhibits	Previously Filed* With File Number	As Exhibit
10(ooo)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(zzz)	—	Tax Sharing Agreement, dated as of October 10, 2007, among Energy Future Holdings Corp., Oncor Electric Delivery Company LLC and Oncor Electric Delivery Holdings Company LLC
10(ppp)	333-100240 Form 10-Q(Quarter ended September 30, 2008) (filed November 6, 2008)	3(a)	—	Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Company LLC, dated as of November 5, 2008
10(qqq)	1-12833 Form 10-Q(Quarter ended September 30, 2008) (filed November 6, 2008)	10(g)	—	Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Holdings Company LLC, dated as of November 5, 2008
10(rrr)	333-100240 Form 10-Q(Quarter ended September 30, 2008) (filed November 6, 2008)	4(c)	—	Investor Rights Agreement, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp.
10(sss)	333-100240 Form 10-Q(Quarter ended September 30, 2008) (filed November 6, 2008)	4(d)	—	Registration Rights Agreement of Oncor Electric Delivery Company LLC, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp.
10(ttt)	333-100240 Form 10-Q(Quarter ended September 30, 2008) (filed November 6, 2008)	10(b)	—	Amended and Restated Tax Sharing Agreement, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Oncor Management Investment LLC, Texas Transmission Investment LLC, Energy Future Intermediate Holding Company LLC and Energy Future Holdings Corp.
10(uuu)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(cccc)	—	Indemnification Agreement, dated as of October 10, 2007 among Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp., Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and Goldman Sachs & Co.
(12)	Statement Regarding Computation of Ratios
12(a)			—	Computation of Ratio of Earnings to Fixed Charges, and Ratio of Earnings to Combined Fixed Charges and Preference Dividends

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Exhibits	Previously Filed* With File Number	As Exhibit
(21)	Subsidiaries of the Registrant
21(a)				—	Subsidiaries of Energy Future Holdings Corp.
(31)	Rule 13a - 14(a)/15d - 14(a) Certifications
31(a)				—	Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31(b)				—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Section 1350 Certifications
32(a)				—	Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32(b)				—	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(99)	Additional Exhibits
99(a)	Post-Effective Amendment No. 1 to 33-55408 Form S-3 (filed July, 1993)	99	(b)	—	Amended Agreement dated as of January 30, 1990, between Energy Future Competitive Holdings Company (formerly known as Texas Utilities Electric Company) and Tex-La Electric Cooperative of Texas, Inc.
99(b)				—	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2008 and 2007
99(c)				—	TCEH Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2008 and 2007

* Incorporated herein by reference

** Certain instruments defining the rights of holders of long-term debt of the registrant’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 registrant and its subsidiaries on a consolidated basis. Registrant hereby agrees, upon request of the SEC, to furnish a copy of any such omitted instrument.

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SIGNATURES

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

	ENERGY FUTURE HOLDINGS CORP.
Date: March 2, 2009	By	/s/ JOHN F. YOUNG
		(John F. Young, President and Chief Executive Officer)

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

Signature	Title	Date
/s/ JOHN F. YOUNG	Principal Executive	March 2, 2009
(John F. Young, President and Chief Executive Officer)	Officer and Director
/s/ PAUL M. KEGLEVIC	Principal Financial Officer	March 2, 2009
(Paul M. Keglevic, Executive Vice President and Chief Financial Officer)
/s/ STANLEY J. SZLAUDERBACH	Principal Accounting Officer	March 2, 2009
(Stanley J. Szlauderbach, Senior Vice President and Controller)
/s/ DONALD L. EVANS	Director	March 2, 2009
(Donald L. Evans, Chairman of the Board)
/s/ ARCILIA C. ACOSTA	Director	March 2, 2009
(Arcilia C. Acosta)
/s/ DAVID BONDERMAN	Director	March 2, 2009
(David Bonderman)
/s/ THOMAS D. FERGUSON	Director	March 2, 2009
(Thomas D. Ferguson)
/s/ FREDERICK M. GOLTZ	Director	March 2, 2009
(Frederick M. Goltz)
/s/ JAMES R. HUFFINES	Director	March 2, 2009
(James R. Huffines)
/s/ SCOTT LEBOVITZ	Director	March 2, 2009
(Scott Lebovitz)
/s/ JEFFREY LIAW	Director	March 2, 2009
(Jeffrey Liaw)
/s/ MARC S. LIPSCHULTZ	Director	March 2, 2009
(Marc S. Lipschultz)
/s/ MICHAEL MACDOUGALL	Director	March 2, 2009
(Michael MacDougall)

294

Signature	Title	Date
/s/ LYNDON L. OLSON, JR.	Director	March 2, 2009
(Lyndon L. Olson, Jr.)
/s/ KENNETH PONTARELLI	Director	March 2, 2009
(Kenneth Pontarelli)
/s/ WILLLIAM K. REILLY	Director	March 2, 2009
(William K. Reilly)
/s/ JONATHAN D. SMIDT	Director	March 2, 2009
(Jonathan D. Smidt)
/s/ KNEELAND YOUNGBLOOD	Director	March 2, 2009
(Kneeland Youngblood)

295