Energy Future (TXU) 10-K 2007 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2007

— 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  Ö  

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    Ö    No        

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  Ö  

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.        

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  Ö  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  Ö  

As of March 25, 2008, there were 1,664,945,952.50 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	15
Item 1B.	UNRESOLVED STAFF COMMENTS	28
Item 3.	LEGAL PROCEEDINGS	28
Item 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	33
PART II
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	33
Item 6.	SELECTED FINANCIAL DATA	34
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	37
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	95
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	101
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	187
Item 9A(T).	CONTROLS AND PROCEDURES	187
Item 9B.	OTHER INFORMATION	191
PART III
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	191
Item 11.	EXECUTIVE COMPENSATION	198
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	238
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	241
Item 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	243
PART IV
Item 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	245

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.

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, TCEH, TXU Energy, Luminant entities, 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
2006 Form 10-K/A	EFH Corp.’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2006
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 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 Exhibit 99.(b)) solely because of the important role that Adjusted EBITDA plays in respect of the certain covenants contained in the 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.
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, formerly referred to as the TXU Energy Holdings segment, which includes TCEH and equipment salvage and resale activities related to eight canceled coal-fueled generation units.
EBITDA	Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization.
EFC Holdings	Refers to Energy Future Competitive Holdings Company (formerly TXU US Holdings Company), a subsidiary of EFH Corp. and the parent of TCEH.
EFH Corp.	Refers to Energy Future Holdings Corp. (formerly TXU Corp.), a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include TCEH and Oncor.
EITF 02-3	Emerging Issues Task Force Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities”
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
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 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, “Accounting for Uncertainty in Income Taxes”
Fitch	Fitch Ratings, Ltd. (a credit rating agency)
FSP	FASB Staff Position
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 wholly-owned subsidiary of EFH Corp. established in connection with the closing of the Merger to own 100% of the equity 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.
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 (formerly TXU Portfolio Management Company LP), a subsidiary of TCEH that engages in certain wholesale markets activities
Luminant entities	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 Operating System	Refers to a program to drive ongoing productivity improvements in Luminant Power’s operations through application of lean operating techniques and deployment of a high-performance industrial culture.
Luminant Power	Refers to subsidiaries of TCEH engaged in electricity generation activities.

iv

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 TXU 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 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, engaged in regulated electricity transmission and distribution activities.
Oncor Holdings	Refers to Oncor Electric Delivery Holdings Company LLC, a wholly-owned subsidiary of Intermediate Holding and the parent of Oncor.
Oncor Ring-Fenced Entities	Refers to Oncor Holdings and its direct and indirect subsidiaries.
OPEB	other postretirement employee benefits
price-to-beat rate	residential and small business customer electricity rates established by the PUCT that (i) were required to be charged in a REP’s historical service territories until the earlier of January 1, 2005 or the date when 40% of the electricity consumed by such customer classes was supplied by competing REPs, adjusted periodically for changes in fuel costs, and (ii) were required to be made available to those customers until January 1, 2007
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act
Purchase accounting	The purchase method of accounting for a business combination as prescribed by 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.

v

Regulated Delivery segment	Refers to the EFH Corp. business segment, formerly referred to as the TXU Electric Delivery 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)
SEC	US Securities and Exchange Commission
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 115	SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities”
SFAS 123R	SFAS No. 123 (revised 2004), “Share-Based Payment”
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 125”
SFAS 141	SFAS No. 141, “Business Combinations”
SFAS 141R	SFAS No. 141R (revised 2007), “Business Combinations”
SFAS 142	SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 143	SFAS No. 143, “Accounting for Asset Retirement Obligations”
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”
SFAS 159	SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”

vi

SFAS 160	SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51”
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.
TCEH	Refers to Texas Competitive Electric Holdings Company LLC (formerly TXU Energy Company LLC), a direct subsidiary of EFC Holdings and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, engaged in electricity generation, wholesale and retail energy markets and development and construction activities. Its major subsidiaries include the Luminant entities and TXU Energy.
TCEH Finance	Refers to TCEH Finance, Inc., a 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 17 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 is the parent of EFH Corp.
Texas Holdings Group	Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities.
TXU Energy	Refers to TXU Energy Retail Company LLC, a 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
USCAP	US Climate Action Partnership

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. (formerly TXU 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 Luminant, which is engaged in electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases, and commodity risk management and trading activities, and TXU Energy, which is engaged in retail electricity sales. Oncor is engaged in regulated electricity transmission and distribution operations in Texas.

With the closing of the Merger on October 10, 2007, EFH Corp. became a wholly owned subsidiary of Texas Holdings, a Delaware limited partnership controlled by the Sponsor Group, and the outstanding shares of common stock of EFH Corp. were converted into the right to receive $69.25 per share.

As of December 31, 2007, Luminant owned or leased 18,365 MW of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas/fuel oil-fueled generation facilities. In addition, Luminant is the largest purchaser of wind-generated electricity in Texas and the fifth largest in the US. Luminant is currently constructing three lignite/coal-fueled generation units in Texas with expected generation capacity totaling approximately 2,200 MW. Air permits have been obtained for the three units, which are expected to come on-line in 2009 and 2010. TXU Energy provides competitive electricity and related services to more than 2.1 million retail electricity customers in Texas. As of December 31, 2007, TXU Energy’s estimated share of the total ERCOT retail market for residential and small business electricity customers was approximately 36% and 25%, respectively (based on customer counts).

Oncor is an electricity distribution and transmission company that is primarily regulated by the PUCT. It 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 distribution and transmission system in Texas, delivering electricity to more than three million homes and businesses and operating more than 116,000 miles of transmission and distribution lines in Texas.

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 Texas Holdings or any of its other subsidiaries in the event of a bankruptcy of one or more of those entities. See Note 1 to Financial Statements for more information.

At December 31, 2007, EFH Corp. had approximately 7,600 full-time employees, including approximately 2,500 employees under collective bargaining agreements.

EFH Corp.’s Market

EFH Corp. operates primarily within the ERCOT market, which 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 approximately 250 members, including electric cooperatives, municipal power agencies, investor-owned independent generators, independent power marketers, transmission service providers, distribution service providers, independent REPs and consumers.

1

The ERCOT market represents approximately 75% of the geographical area of Texas, but excludes El Paso, a large part of the Texas Panhandle and two small areas in the eastern part of the state. From 1996 through 2006, peak hourly demand in the ERCOT market grew at a compound annual rate of 2.8%, compared to a compound annual rate of growth of 2.5% for the entire US over the same period. For 2006, the most recent period for which full year data is available, hourly demand ranged from a low of 21,309 MW to a high of 62,339 MW. 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 not subject to regulation by the FERC.

Since 1999, over 29,000 MW of mostly natural gas-fueled and wind generation capacity has been developed in the ERCOT market. As of December 2007, net generation capacity in the ERCOT market totaled approximately 81,000 MW, which included approximately 5,000 MW of mothballed capacity; approximately 68% of the 81,000 MW is natural gas-fueled. Approximately 25% of this total capacity consists of lower marginal cost, as compared to natural gas-fueled facilities, lignite/coal and nuclear-fueled baseload generation. Luminant’s baseload plants represent approximately 40% of the total ERCOT market baseload generation capacity. ERCOT currently has a target reserve margin level of approximately 12.5%; the reserve margin is projected by ERCOT to be 13.1% in 2008 and drop to 8.2% by 2013.

Natural gas-fueled generation is the predominant electricity capacity resource in the ERCOT market and accounted for approximately 46% of the electricity produced in the ERCOT market in 2006. 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. ERCOT’s October 1, 2005 report titled “Report on Existing and Potential Electric System Constraints and Needs” found that natural gas-fueled plants set the market price more than 90% of the time in the ERCOT market. As a result, wholesale electricity prices are highly correlated to natural gas prices.

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. Luminant’s baseload generation units are located primarily in the North region, with the Sandow unit in the South region.

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 ERCOT 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 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.

2

EFH Corp.’s Strategies

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

• Luminant focuses on optimizing its existing generation fleet to provide safe, reliable and cost-competitive electricity, as well as developing and constructing additional generation capacity to help meet the growing demand for electricity in Texas;

• TXU Energy focuses on providing high quality customer service and developing innovative energy products to meet customers’ needs, and

• Oncor focuses on maintaining safe operations, achieving a high level of reliability, minimizing service interruptions and investing in its transmission and distribution infrastructure to serve a 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 reliability, cost and customer service. EFH Corp. will continue to focus on upgrading four critical skill sets: operational excellence across each business; market leadership; a systematic risk/return mindset applied to all key decisions; and rigorous performance management targeting industry-leading performance standards for productivity, reliability and customer service. An example of how EFH Corp. implements these principles is a program called the “Luminant Operating System,” which is a program to drive ongoing productivity improvements in Luminant Power’s operations through application of lean operating techniques and deployment of a high-performance industrial culture.

• Pursue growth opportunities across business lines. EFH Corp. will selectively target growth opportunities in each of its business lines. EFH Corp.’s scale in each of its operating businesses allows it to take part in large capital investments, such as new generation projects and investments in Oncor’s 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 EFH Corp.’s performance over the near term but can enhance its growth profile over time. Specific growth initiatives for each business include:

• Luminant: Construct three new lignite-fueled generation facilities with onsite lignite fuel supplies, as well as pursue wind generation projects in the near to medium term. 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, renewables and advanced coal technologies.

• TXU Energy: Increase the number of customers served both in EFH Corp.’s historical service territory and in other competitive ERCOT areas such as Houston, by delivering superior value to customers through superior customer service and innovative energy products, including pioneering energy efficiency initiatives and service offerings.

• Oncor: Invest in technology upgrades including advanced meter reading systems and construct new transmission and distribution facilities to meet the needs of the growing Texas market. Oncor and other transmission and distribution businesses in ERCOT benefit from regulatory capital recovery mechanisms known as “capital trackers” that Oncor believes enable adequate and timely recovery of transmission investments and advanced meter reading investments through the rates charged by Oncor.

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 Luminant’s baseload generation output on a rolling five-year basis. 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 March 14, 2008, approximately 2.4 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 305,000 GWh at an assumed 8.0 MMBtu/MWh market heat rate) have been effectively sold forward by EFH Corp.’s subsidiaries over the period from 2008 to 2013, at average annual prices ranging from $7.25 per MMBtu to $8.15 per MMBtu. Taking into consideration the estimated portfolio impacts of EFH Corp.’s retail electricity business, these natural gas hedging transactions result in EFH Corp. having effectively hedged approximately 84% of its expected baseload generation natural gas price exposure (on an average basis for 2008 through 2013). Certain of the hedging transactions are directly secured with a first-lien interest in TCEH’s assets, which eliminates 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 March 14, 2008, approximately 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. has formed a Sustainable Energy Advisory Board that will advise EFH Corp. in its pursuit of technology development opportunities that reduce EFH Corp.’s impact 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. In addition, EFH Corp. is focused on and is pursuing opportunities to reduce emissions from its existing and planned new lignite/coal-fueled generation units in the ERCOT market. Luminant has voluntarily committed to reduce emissions of mercury, nitrogen oxide and sulfur dioxide 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. Luminant expects to make these reductions through a combination of investment in new emission control equipment, new coal cleaning technologies and optimizing fuel blends. Luminant also expects such investments to provide economic benefits by reducing future costs associated with complying with environmental emissions standards. EFH Corp. expects that its subsidiaries will invest $400 million over a five year period beginning in 2008 in programs designed to encourage customer electricity demand efficiencies, representing $200 million more than amounts planned to be invested by Oncor prior to the Merger.

Operating Segments

EFH Corp. has aligned and reports its business activities as two operating segments: Competitive Electric (primarily represented by TCEH) and Regulated Delivery (primarily represented by Oncor).

Competitive Electric Segment

Commodity risk management and allocation of financial resources is performed at the Competitive Electric segment (TCEH) level. For purposes of operational accountability and performance management, the segment has been divided into the Luminant entities (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.

4

Luminant Power —Luminant Power’s electricity generation fleet consists of 19 plants in Texas with total generating capacity as of December 31, 2007 as shown in the table below:

Fuel Type	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.

(c) Includes 585 MW representing nine combustion turbine units currently operated for an unaffiliated third party’s benefit.

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 variable consumption as production from 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 is expected to occur 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 2007 55-day outage 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 32 days in 2005 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 of US nuclear generation facilities, and 93.5% in 2007, reflecting a planned extended refueling outage to replace the steam generator and reactor vessel head in Unit 1.

Luminant Power has contracts in place for nuclear fuel conversion services through 2008. In addition, Luminant Power has contracts for the acquisition of 100% and 73% of its uranium requirements in 2008 and 2009, respectively and for 91% of the nuclear fuel enrichment services through 2009, as well as 100% of nuclear fuel fabrication services through 2018.

Contracts for the acquisition of additional raw uranium and nuclear fuel conversion services through 2016 and 2015, respectively, are being negotiated. Additional offers to ensure a portion of nuclear fuel enrichment services through 2020 are under review. Luminant Power does not anticipate any material issues with finalizing these contracts and does not anticipate any significant difficulties in acquiring raw uranium and contracting for associated conversion services and enrichment in the foreseeable future.

Luminant Power’s on-site used nuclear fuel storage capability is sufficient for five to ten 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 the requisite 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 is funded from Oncor’s customers through an ongoing delivery surcharge.

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Lignite/Coal-Fueled Generation Assets — Luminant Power’s 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 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 30 days. Luminant Power’s lignite/coal-fueled generation fleet operated at a capacity factor of 89.1% in 2006 and 90.9% in 2007, which represents top decile performance of US coal-fueled generation facilities.

Approximately 63% of the fuel used at Luminant Power’s lignite/coal-fueled generation plants in 2007 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 893 million tons of lignite reserves dedicated to its generation plants, including the Oak Grove generation facilities being constructed, and including 246 million tons obtained in conjunction with the 2007 acquisition of an undivided interest in a lignite mine that fuels 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 2007, approximately 22 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 2007, Luminant Power reclaimed 1,671 acres of land and regulatory authorities approved Luminant Power’s release of approximately 200 acres from further reclamation obligation. In addition, EFH Corp. planted more than 1.6 million trees in 2007, 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 82% of its western coal resources and 100% of the related transportation through 2009.

Natural Gas-Fueled Generation Assets — Luminant Power’s fleet of 45 natural gas-fueled generation units consists of 8,314 MW of currently available capacity, 585 MW of capacity being operated for an unaffiliated third party’s benefit, pursuant to the direction of that unaffiliated third party, and 1,329 MW of capacity currently mothballed. A significant number of the natural gas-fueled units have the ability to switch between natural gas and fuel oil. The gas units predominantly serve as peaking units that can be more readily ramped up or down as demand warrants.

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 electricity 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 United States.

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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 procurement requirements for these plants.

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 well-head production contracts, transportation agreements, storage leases and retail sales. Luminant Energy currently manages approximately 19 billion cubic feet of natural gas storage capacity and has a small presence outside of Texas in both electricity and natural gas commodity trading.

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 commodity 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.

Luminant Construction— Luminant Construction is developing three new lignite-fueled units in the state of 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 plant site (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.

Development and procurement activities for the three new lignite-fueled units are essentially complete and construction is well underway. Air permits have been obtained, and EPC agreements have been executed with Bechtel Power Corporation and Fluor Enterprises, Inc. The expected commercial operation dates of the units are as follows: Sandow in 2009 and Oak Grove’s two units in 2009 and 2010. (See Note 18 to Financial Statements for additional information about the air permits, including actions of opponents to the development of the 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 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 billion to $1.3 billion. Luminant Construction has not yet completed detailed cost and engineering studies for the additional environmental systems, and the cost estimates could change substantially 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 2.1 million retail electricity customers, of which 1.8 million are in EFH Corp.’s historical service territory. This territory, which is located in the north-central, eastern and western parts of Texas, has an estimated population in excess of 7 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.

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Texas is one of the fastest growing states in the nation with a diverse and resilient 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 the other areas of the ERCOT market now open to competition, including the 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, 2007, there are more than 100 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. For the year ended December 31, 2007, call answer times averaged less than 15 seconds. Customer call satisfaction scores in North Texas improved 9% in the year ended December 31, 2007, as compared to the year ended December 31, 2006. TXU Energy offers 10 widely available residential products to meet various customer needs, currently more than any retailer in the ERCOT market. TXU Energy is also planning to invest $100 million over the next five years in energy efficiency initiatives as part of a program to offer customers a broad set of innovative energy products and services.

Since March 2007, TXU Energy has implemented price reductions totaling 15% for residential customers in EFH Corp.’s historical service territory who have not already switched from the basic month-to-month plan to one of the other pricing plans offered by TXU Energy. These customers received a six percent reduction beginning in late March 2007, an additional four percent reduction in June 2007 and an additional five percent reduction effective in late October 2007. TXU Energy has committed to provide price protection to these customers through December 2008, ensuring that they receive the benefits of the majority of these savings through two summer seasons of peak energy usage. 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 price-to-beat rate.

As of December 31, 2007, TXU Energy served approximately 62% of the retail residential market share in EFH Corp.’s historical service territory and approximately 36% of the total ERCOT competitive retail residential market.

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.

As a result of the legislation that restructured the electric utility industry in Texas to provide for retail competition (1999 Restructuring Legislation), effective January 1, 2002, REPs affiliated with electricity delivery utilities were required to charge price-to-beat retail prices, established by the PUCT, to residential and small business customers located in their historical service territories. The price-to-beat mechanism was intended to spur competition as the rates were set such that competing REPs could profitably offer lower rates. TXU Energy, as a REP affiliated with an electricity delivery utility, was required to charge the price-to-beat retail price, adjusted for fuel factor changes, to these classes of customers until the earlier of January 1, 2005 or the date on which 40% of the electricity consumed by customers in that class was supplied by competing REPs. TXU Energy met the 40% threshold target calculation for its small business customers in December 2003 and began offering rates other than the price-to-beat retail prices to this customer class. Since January 1, 2005, TXU Energy has offered rates different from the price-to-beat retail prices to all customer classes, but was required to make the price-to-beat retail prices available for residential and small business customers in EFH Corp.’s historical service territory until January 1, 2007.

Regulated Delivery Segment

The Regulated Delivery segment primarily consists of the operations of Oncor. Oncor is a regulated electricity transmission and distribution company, which 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. Oncor’s operating 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.

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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.

Investing in Infrastructure and Technology —In 2007, Oncor invested over $750 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, information technology systems and advanced meter reading. By the end of 2007, Oncor had approximately 600,000 advanced meters installed as part of a plan to have all of its approximately three million meters converted by 2012. The advanced meters can be read automatically, rather than by a meter reader physically visiting the location of each meter. Advanced meters may also eventually provide automated demand side management.

Oncor achieved market-leading electricity delivery performance in five out of seven key PUCT market metrics in 2007. These metrics measure the success of transmission and distribution companies in facilitating customer transactions in the competitive Texas electricity market.

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. The transmission business 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 the 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 4,873 circuit miles of 345-kV transmission lines and 9,789 circuit miles of 138-and 69-kV transmission lines. Fifty-two generation plants totaling 33,794 MW are directly connected to Oncor’s transmission system, and 268 transmission stations and 708 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	96	21
Rayburn Country Electric Cooperative	—	29	7
City of Georgetown	—	2	—
Tex-La Electric Cooperative	—	9	1
Other small systems operating wholly within Texas	—	4	2

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

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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 3,000 distribution feeders.

The Oncor distribution system includes over three million points of delivery. Over the past five years, the number of Oncor’s distribution system points of delivery served, excluding lighting sites, has been growing an average of approximately 1.5% per year, adding approximately 45,000 points of delivery in 2007.

The Oncor distribution system consists of 56,171 miles of overhead primary conductors, 21,711 miles of overhead secondary and street light conductors, 14,972 miles of underground primary conductors and 9,351 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 41% of Oncor’s total revenues for 2007. 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.

Seasonality—A significant portion of Oncor’s revenues is derived from rates that Oncor collects from REPs based on the amount of electricity Oncor distributes on behalf of REPs. As a result, the revenues and results of operations of Oncor are subject to seasonality, weather conditions and other changes in electricity usage, with revenues being higher during the warmer months.

Regulation and Rates —As its operations are wholly within Texas, Oncor believes that it 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 with a final order entered in February 2008, Oncor has agreed to file a rate case with the PUCT no later than July 1, 2008, based on a test year ended December 31, 2007.

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—Oncor’s consolidated financial statements include its wholly-owned, bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC. Oncor Electric Delivery Transition Bond Company LLC was organized for the limited purpose of issuing 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

Climate Change and Carbon Dioxide

Luminant’s nine lignite/coal-fueled generation units are significant sources of CO₂ emissions, generating the great majority of the average of 57 million tons of CO₂ that Luminant’s monitoring indicates its generation plants produced annually from 2004 to 2006. The three new lignite-fueled units currently under construction will generate additional CO₂ emissions.

In November 2007, Luminant applied for membership in USCAP, which is a broad-based group of businesses and leading environmental groups organized to work with the President, the Congress and all other stakeholders to enact environmentally effective and economically sustainable climate change programs. EFH Corp. supports a mandatory cap and trade program to reduce CO₂ emissions as part of its affiliation with USCAP. EFH Corp. participates in a voluntary electric utility industry sector climate change initiative in partnership with the US Department of Energy. This initiative supports the Bush Administration’s greenhouse gas emissions intensity reduction program, Climate VISION. EFH Corp.’s strategies are consistent with The Carbon Principles announced in February 2008 by three major financial institutions that focus on energy efficiency, renewable and low carbon distributed energy technologies and conventional and advanced generation.

EFH Corp.’s approach to addressing global climate change is based upon the following principles:

• Climate change is a global issue requiring a comprehensive solution addressing all greenhouse gases, sources and economic sectors in all countries;

• Development of US energy and environmental policy should seek to ensure US energy security and independence;

• Solutions should encourage investment in a diverse supply of new generation to meet US needs to maintain adequate reserve margins and support economic growth, as well as address customer’s needs for affordable and reliable energy;

• Policies should encourage significant investments in research and development and deployment of a broad spectrum of solutions, including energy efficiency, renewable energy and coal, natural gas and nuclear-fueled generation technologies, and

• Any mandate to reduce greenhouse gas emissions should be developed under a market-based framework that is consistent with expected technology development timelines and supports the displacement of old, inefficient power generation technology with advanced, more efficient technology.

EFH Corp.’s strategies for lowering greenhouse gas emissions include:

• Investing in technology — EFH Corp. expects to invest over the next five to seven years in the development and commercialization of cleaner power plant technologies, including integrated gasification combined cycle, the next generation of more efficient ultra-supercritical coal and pulverized coal emissions technology to reduce CO₂ emission intensity. A number of actions, including research and development investments and partnerships, have already been initiated to advance next-generation technologies;

• Providing electricity from renewable sources — EFH Corp. intends to become a leader in providing electricity from renewable sources by more than doubling its purchases of wind power to more than 1,500 MW. In 2007, Luminant added 124 MW to its wind power portfolio bringing its total wind power portfolio to more than 900 MW. EFH Corp. also intends to promote solar power through solar/photovoltaic rebates;

• Committing to demand side management initiatives — EFH Corp. expects that its subsidiaries will invest $400 million over five years beginning in 2008 in programs designed to encourage customer electricity demand efficiencies that represents $200 million more than amounts planned to be invested prior to the Merger as part of demand side management initiatives within Oncor’s regulated operations;

• Reducing CO₂ emissions by increasing production efficiency — Luminant expects to increase production efficiency of its existing generation facilities by up to 2 percent, and

• Evaluating the development of a nuclear generation facility — Luminant plans to develop an application to file with the NRC for combined construction and operating licenses for up to 3,400 MW of new nuclear generation capacity at its Comanche Peak nuclear generation plant. Nuclear generation is the lowest emission source of baseload generation available.

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Increasing public concern and political pressure from local, regional, national and international bodies may result in the passage of new laws mandating limits on greenhouse gas emissions. A series of reports by the Intergovernmental Panel on Climate Change in 2007 attracted considerable public attention and concern. Several bills addressing climate change have been introduced in the US Congress and, in April 2007, the US Supreme Court issued a decision ruling the EPA improperly declined to address CO₂ impacts in a rulemaking related to new motor vehicle emissions. While this decision is not directly applicable to power plant emissions, the reasoning of the decision could affect other regulatory programs. Various proposals in the US Congress could require EFH Corp. to purchase offsets or allowances for some or all of its CO₂ emissions, or otherwise affect EFH Corp. based on the amount of CO₂ it generates. The impact on EFH Corp. of any future greenhouse gas regulation will depend in large part on the details of the requirements and the timetable for mandatory compliance. EFH Corp. continues to assess the financial and operational risks posed by possible future legislative changes pertaining to greenhouse gas emissions, but because these proposals are in the formative stages, EFH Corp. is unable to predict any future impacts on its financial condition and operations.

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_x emission standards. Luminant’s generation plants meet the SO₂ allowance requirements and NO_x emission rates.

In 2005, the EPA issued a final rule to further reduce SO₂ and NO_x emissions from power plants. The SO₂ and NO_x reductions required under the Clean Air Interstate Rule (CAIR), which are required to be phased in between 2009 and 2015, are based on a cap and trade approach (market-based) in which a cap is put on the total quantity of emissions allowed in 28 eastern states (including Texas). Emitters are required to have allowances for each ton emitted, and emitters are allowed to trade emissions under the cap. Luminant has received its NO_x allowances under CAIR for the years 2009 through 2014.

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) is based on a cap and trade approach on a nationwide basis. The mercury reductions are required to be phased in between 2010 and 2018. In February 2008, the United States Court of Appeals for the D.C. Circuit issued a decision that would vacate the CAMR rule and in March 2008, this Court issued a mandate vacating CAMR. Depending on the outcome of any appeals, CAMR could be reinstated. If appeals are unsuccessful, the EPA must begin development of rules implementing maximum achievable control technology, which will take several years.

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 would be required on a unit-by-unit basis. The EPA provides the option for states to use CAIR to satisfy the BART reductions for electric generating units, and Texas has chosen this option.

In connection with Luminant’s plan to build 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. 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 the CAIR, CAMR and BART rules to provide the most cost-effective compliance plan options.

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

• To reduce NO_x emissions, Luminant plans to install in-duct selective catalytic reduction (SCR) systems at its Martin Lake plant. In addition, Luminant 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 Luminant’s new and existing plants plan to use activated carbon injection — a sorbent injection system technology, and

• To reduce SO₂ emissions, various plants plan to increase use of lower-sulfur coal. 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 also 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 the eight-hour ozone standards. These rules require further NO_x emission reductions from certain Luminant Power peaking natural gas-fueled units in the Dallas-Fort Worth area by spring 2009. 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 five years, Luminant Power 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. 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 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.

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 any new regulations that replace them.

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Radioactive Waste

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. 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.)

Luminant Power believes that its on-site used nuclear fuel storage capability is sufficient for five to ten 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.

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.

Environmental Capital Expenditures

Capital expenditures for EFH Corp.’s environmental projects totaled $65 million in 2007 and are expected to total approximately $200 million in 2008, exclusive of emissions control equipment investment planned as part of the three-unit Texas 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, and 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, 2007, EFH Corp.’s consolidated debt (short term borrowings and long-term debt, including amounts due currently) totaled $40.8 billion. EFH Corp.’s substantial leverage could have important consequences, including:

• making it more difficult for EFH Corp. to make payments on 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 certain of its 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, 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.’s substantial leverage prevents it from exploring.

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.

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 which 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, and

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

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In addition, 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.

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, 2007, TCEH and its subsidiaries held approximately 76% of EFH Corp.’s consolidated assets. Accordingly, EFH Corp. depends upon TCEH for a significant amount of its cash flows and ability to pay its obligations. For the year ended December 31, 2007, TCEH and its subsidiaries represented 81% of EFH Corp.’s consolidated revenues. However, under the terms of TCEH’s debt agreements, TCEH is restricted from making certain payments to EFH Corp., except in limited circumstances. In addition, TCEH is prohibited from making certain loans to EFH Corp. if certain events of default under the debt agreements have occurred and are continuing.

EFH Corp. may not be able to generate sufficient cash to service all of EFH Corp.’s indebtedness and may be forced to take other actions to satisfy EFH Corp.’s obligations under EFH Corp.’s debt agreements, which may not be successful.

EFH Corp.’s ability to make scheduled payments on or to refinance debt obligations depends on its financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond EFH Corp.’s control. EFH Corp. may not be able to maintain a level of cash flows from operating activities sufficient to permit it to pay the principal, premium, if any, and interest on its indebtedness.

If cash flows and capital resources are insufficient to fund debt service obligations, EFH Corp. may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance indebtedness. These alternative measures may not be successful and may not permit EFH Corp. to meet scheduled debt service obligations.

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, whether by dividends, distributions, loans or otherwise. 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, 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.

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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.

As a result of the ring-fencing measures undertaken by EFH Corp. and Oncor, there can be no assurance that Oncor will 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 Texas Holdings and its other subsidiaries in order 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 Texas Holdings or any of its other subsidiaries 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 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, a majority of whose members are required to be independent from EFH Corp. The organizational documents of Oncor give these independent directors the express right, acting by majority vote, 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.

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 as of January 1, 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) and 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 also 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 its 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 or with respect to the required permits for the three lignite-fueled generation units currently under construction) may have an adverse effect on EFH Corp.’s businesses.

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Although the 2007 Texas Legislative Session closed without passage of legislation that significantly negatively impacted EFH Corp.’s businesses, the legislature did adopt legislation that likely requires prior PUCT approval for any future direct or indirect disposition 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 on April 25, 2007). Several pieces of legislation were introduced that, 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 electric prices.

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 most recent Texas Legislature, will not have a material adverse effect on EFH Corp. and its financial prospects. The Texas Legislature’s next session begins in January 2009. The outcome of any legislation promulgated 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 management 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. For example, in March 2007, the PUCT issued a Notice of Violation (NOV) stating that the PUCT Staff is 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. The PUCT Staff issued a revised NOV in September 2007, 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 is 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. A hearing requested by Luminant Energy to contest the alleged occurrence of a violation and the amount of the penalty in the NOV was initially scheduled to start in April 2008, but was stayed pending resolution of discovery disputes and Luminant Energy’s motion to dismiss, which was filed in November 2007. The motion to dismiss was denied by the state administrative law judges, and in February 2008 the PUCT declined to hear Luminant Energy’s appeal of that denial. While it believes no market power abuse was committed, EFH Corp. is unable to predict the outcome of this matter.

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TXU Energy may lose a significant number of retail customers in EFH Corp.’s historical service territory due to competitive marketing activity by retail electric providers and face competition from incumbent providers outside EFH Corp.’s historical service territory.

TXU Energy faces competition for customers within EFH Corp.’s historical service territory. 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 most retail electric markets outside EFH Corp.’s historical service territory, TXU Energy’s principal competitor may be the retail affiliate of the local incumbent utility company. The incumbent retail affiliates have the advantage of long-standing relationships with their customers, including well-known brand recognition.

In addition to competition from the incumbent utilities and their affiliates, TXU Energy may face competition from a number of other energy service providers, or other energy industry participants, who may develop businesses that will compete with TXU Energy and nationally branded providers of consumer products and services. 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.

EFH Corp.’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.

EFH Corp. 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. EFH Corp.’s results of operations depend in large part upon market prices for electricity, natural gas, uranium and coal 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. Further, TXU Energy granted price discounts to certain of its customers in connection with the Merger, and has agreed to provide price protection to these customers through December 2008.

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:

• 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 and market heat rates;

• outages at EFH Corp.’s generation facilities or those of competitors;

• 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.

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All of Luminant Power’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 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 Luminant Power’s baseload (lignite/coal-fueled and nuclear) generation assets, which provided a substantial portion of EFH Corp.’s supply volumes in 2007, are dependent in significant part upon the price of natural gas and market heat rates. As a result, Luminant Power’s baseload generation assets could significantly decrease in profitability and value if natural gas prices or market heat rates fall.

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 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 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 sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Although EFH Corp. devotes a considerable amount of management 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 be followed or may not always function as planned and cannot eliminate all the risks associated with these activities. 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.

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 in 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.

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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, the Luminant entities have committed to reduce emissions of mercury, nitrogen oxide (“NO_X”) and sulfur dioxide (“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 will advise it in its pursuit of technology development opportunities that, among other things, are designed to reduce EFH Corp.’s impact on the environment. If any of the Sustainable Energy Advisory Board’s recommendations are adopted, EFH Corp. may incur significant costs in addition to the costs referenced above as it pursues these recommendations.

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 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.

Increasing attention to potential environmental effects of “greenhouse” gas emissions may result in new regulation and restrictions on emissions of certain gases that may be contributing to warming the earth’s atmosphere. Several bills addressing climate change have been introduced in the US Congress and, in April 2007, the US Supreme Court issued a decision ruling the EPA improperly declined to address carbon dioxide impacts in a rulemaking related to new motor vehicle emissions. While this decision is not directly applicable to power plant emissions, the reasoning of the decision could affect other regulatory programs. The impact of any future greenhouse gas legislation or other regulation will depend in large part on the details of the requirements and the timetable for mandatory compliance. Although it continues to assess the financial and operational risks posed by possible future legislative changes pertaining to greenhouse gas emissions, EFH Corp. is currently unable to predict any future impact from these changes on its financial condition and operations.

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The rates of Oncor’s electric delivery business are subject to regulatory review.

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 2004, certain cities within Oncor’s service territory, acting in their role as a regulatory authority (with original jurisdiction), initiated inquiries to determine if Oncor’s PUCT-established rates were just and reasonable. Oncor entered into settlements with the cities deferring rate action, but requiring Oncor to file a rate case in 2008 unless Oncor and the cities mutually agree that such a filing is unnecessary. However, the PUCT’s approval of the stipulation as discussed below requires a rate case in 2008, based on a 2007 test year.

In October 2007, several parties to a proceeding before the PUCT related to the Merger, including Oncor and the PUCT Staff, agreed on the terms of a stipulation to resolve all of the outstanding issues in the proceeding. In January 2008, the PUCT approved the stipulation and the final order was entered in February 2008. One of the terms of the stipulation is the dismissal of the Oncor rate case ordered by the PUCT in April 2007 and filed in August 2007, which was based on a test year ended December 31, 2006. As a result of this final order, Oncor expects the PUCT to enter another order dismissing this rate case. The stipulation requires Oncor to file a general rate case with the PUCT no later than July 1, 2008, based on a test year ended December 31, 2007.

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 its 2008 general rate case, support a cost of debt that does not exceed its actual cost of debt immediately prior to the announcement of the Merger. 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 to be filed no later than July 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 Luminant has experience in operating lignite-fueled generation facilities, it has limited recent experience in developing and constructing 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 Luminant 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 these new facilities.

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Luminant’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, electric 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 Luminant has received permits to construct and operate the new units that are a part of the lignite-fueled generation development program, each of these permits is subject to ongoing litigation. An adverse ruling on these matters could materially and adversely effect the implementation of this program.

Luminant’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 new generation assets in ERCOT, Luminant’s program could impact market prices of power 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 Luminant enters into hedges to reduce such exposures, it would still be subject to the credit risk of its counterparties.

Luminant’s lignite-fueled generation development program is subject to other risks that are beyond its control. For example, Luminant 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 Luminant’s new generation facilities. Luminant is subject to risks relating to transmission capabilities and constraints. Luminant 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 electric delivery facilities will be successful, and there can be no assurance that the capital investments Oncor intends to make in connection with its electric delivery business will produce the desired reductions in cost and improvements to service and reliability. In addition, there can be no guarantee that Oncor’s capital investments 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.

The implementation of performance improvement initiatives identified by management may not produce the desired reduction in costs and may result in disruptions arising from employee displacements and the rapid pace of changes to organizational structure and operating practices and processes. Specifically, EFH Corp. is subject to the risk that the joint venture outsourcing arrangement with Capgemini that provides business support services may not produce the desired cost savings. If the Capgemini arrangement is terminated or modified in the future, or if Capgemini becomes financially unable to perform its obligations, EFH Corp. would incur transition costs, which would likely be significant, and would be subject to operational difficulties. Such additional costs or operational difficulties could have an adverse effect on EFH Corp.’s business and financial prospects.

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 or widely publicized 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.

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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.

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

In connection with the Merger, TXU Energy implemented a 15% price reduction for residential customers in EFH Corp.’s historical service territory who have not already switched to one of the pricing plans other than the basic month-to-month plan. In addition, TXU Energy intends to provide price protection for these customers through December 2008, ensuring that these customers receive the benefits of these savings through two summer seasons of peak energy usage. 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, so that it can maintain its REP certification. Any removal or revocation of a REP certification would mean that TCEH or TXU Energy, as applicable, would no longer be allowed to provide electric service to retail customers. Such decertification would have an adverse effect on TXU Energy and EFH Corp.’s financial prospects.

Changes in technology may reduce the value of EFH Corp.’s generation plants and/or Oncor’s electric 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 and photovoltaic (solar) cells. 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 Oncor’s electric delivery facilities. Changes in technology could also alter the channels through which retail electric 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.

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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.

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 an 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 commodity contracts, leases or other agreements. In connection with the Merger, Fitch, Moody’s and S&P downgraded EFH Corp.’s long term debt ratings. EFH Corp. currently intends to sell a 20% minority stake in Oncor to further enhance Oncor’s separation from the Texas Holding Group. Should the sale not be completed, Oncor believes that its long-term debt ratings could be downgraded as much as two notches by one of the rating agencies.

Most of EFH Corp.’s large customers, suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions. As EFH Corp.’s (or an applicable subsidiary’s) credit ratings decline, the costs to operate its businesses will likely increase because counterparties may require the posting of collateral in the form of cash-related instruments, or counterparties may decline to do business with it.

In addition, in connection with the Merger, Oncor has committed to the PUCT that it will, in its 2008 rate case, support a cost of debt that does not exceed its actual cost of debt immediately prior to the announcement of the Merger. As such, in connection with these rate cases, in certain circumstances Oncor may not be able to recover additional debt costs above its cost of debt prior to the Merger.

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 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, 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 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 market;

• changes in interest rates;

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• 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;

• 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.

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.’s being required to provide cash or letter of credit collateral in substantial amounts. In addition, any perceived reduction in EFH Corp.’s credit quality could result in clearing agents or other counterparties requesting additional collateral.

In the event that the governmental agencies that regulate the activities of EFH Corp.’s businesses determine that creditworthiness of 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.

Goodwill and/or other intangible assets not subject to amortization that EFH Corp. has recorded in connection with the Merger are subject to mandatory 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 intangible assets recorded in connection with the Merger are not amortized but 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 reflect material adverse impacts on EFH Corp.’s reported results of operations and financial position in future periods.

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. Additionally, the Merger may have a negative impact on EFH Corp.’s ability to attract and retain key management and other employees. EFH Corp.’s failure to attract new personnel or retain existing personnel could have a material adverse effect on its businesses.

EFH Corp.’s future success depends, to a significant extent, on the abilities and efforts of executive officers and other members of its management team. One or more of EFH Corp.’s executive officers may elect to leave the company as a result of the Merger. EFH Corp.’s executive officers have substantial experience and expertise in EFH Corp.’s industry, which EFH Corp. has relied upon significantly. There can be no assurance that EFH Corp. will be able to attract and retain new members of management to replace any executive officers that may leave. If EFH Corp. is not successful in doing so, its businesses may be adversely affected.

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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 the stockholders of EFH Corp.

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.

Item 3. LEGAL PROCEEDINGS

Litigation – Merger Related

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. On April 27, 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. The Merger Agreement allowed EFH Corp. to solicit other proposals from third parties until April 16, 2007 and the transaction was subject to the approval of EFH Corp.’s former shareholders, which was obtained at the annual meeting of shareholders on September 7, 2007. Accordingly, 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. The Motions are pending before the Court. No further action has been taken by the parties, and the Court has not yet ruled upon the Written Statement and Application, given the memorandum of understanding executed by the parties on July 23, 2007 and the proposed settlement as described below.

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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, allege that EFH Corp.’s former directors, named as defendants, breached fiduciary duties owed EFH Corp. by approving the Merger Agreement. The petitions, now consolidated into one action in the 44^th District Court, Dallas County, Texas, include claims that the defendants failed to ensure that the transaction was in the best interest of EFH Corp.; that the former directors participated in a transaction 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. EFH Corp. believes that the Plaintiffs failed to comply with provisions of the TBOC applicable to filing and pursuing derivative proceedings and filed a Motion to Dismiss that is pending before the Court. Additionally, EFH Corp. filed a Written Statement with the Court advising that, pursuant to the TBOC, a Derivative Demand Committee of independent and disinterested former members of EFH Corp.’s board of directors has been formed and is engaged in the active review, in good faith, of the allegations in the consolidated derivative lawsuits. EFH Corp. also requested that the Court enforce the automatic and mandatory stay of the proceedings as provided in the TBOC until the Derivative Demand Committee has completed its review. On May 16, 2007, the parties agreed to stay the consolidated derivative proceeding pending the Derivative Demand Committee’s review of Plaintiffs’ claims in that proceeding. On May 18, 2007, the Court entered an order staying the action in accordance with Section 21.555 of the TBOC. On July 18, 2007, EFH Corp. filed a Written Statement pursuant to TBOC Section 21.555(c) and an Application for Additional Stay informing the District Court that the Derivative Demand Committee was continuing its active review, in good faith, of the allegations set forth in the derivative lawsuits and accordingly requested an extension of the order staying the action through August 31, 2007. No further action has been taken by the parties, and the Court has not yet ruled upon the Written Statement and Application, given the memorandum of understanding executed by the parties on July 23, 2007 and the proposed settlement as described below.

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, as well as a request 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. The Merger Agreement allowed EFH Corp. to solicit other proposals from third parties until April 16, 2007 and was subject to the approval of EFH Corp.’s former shareholders, which was obtained at the annual meeting of shareholders on September 7, 2007. The consolidated suit purports to assert claims by shareholders directly against the directors. EFH Corp. believes that Texas law does not recognize such a cause of action. Consequently, EFH Corp. and its former directors filed a Motion to Dismiss. On May 25, 2007, the Court granted the Motion and dismissed the consolidated putative class action suit with prejudice. On May 31, 2007, Plaintiffs moved for reconsideration of the May 25 Order dismissing the action; however, Plaintiffs subsequently withdrew this motion. No further action has been taken by the parties, and the Court has not yet ruled upon the Written Statement and Application, given the memorandum of understanding executed by the parties on July 23, 2007 and the proposed settlement as described below.

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On July 19, 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 June 14, 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. EFH Corp. has not yet responded to this litigation and, as described below, on July 23, 2007, the Sponsor Group, joined by EFH Corp. for the limited purpose described below, have entered into a memorandum of understanding with plaintiffs that would result in the dismissal of this litigation if the settlement is approved by the courts. In the event that EFH Corp. is required to respond to this litigation, EFH Corp. will file a Motion to Dismiss based on the fact that this proxy statement clearly and accurately described the information regarding the Merger and the information necessary for a shareholder to evaluate the proposal to approve the Merger Agreement. EFH Corp. believes the claims made in this litigation are without merit and, therefore, if necessary, EFH Corp. intends to vigorously defend this litigation.

On July 23, 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, if approved by the court in which the litigation is pending, to the extent required, all of the litigation related to the Merger described above will be 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 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 on October 10, 2007, EFH Corp. merged with the entity obligated to fund any court approved attorneys’ fees. Accordingly, EFH Corp. is legally obligated for such payment. On January 7, 2008, a final settlement agreement was executed by the Plaintiffs in the above described litigation matters and the defendants and the courts with jurisdiction over the litigation are scheduled to consider the settlements for approval on April 18, 2008. The settlement of the litigation, subject to court approval, will result in a dismissal of all claims related to the Merger against EFH Corp. and its preclosing officers and directors.

Litigation – Generation Facilities

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 on September 7, 2007 in the State District Court of Travis County, Texas. Plaintiffs ask that the District Court reverse TCEQ’s approval of the Oak Grove air permit, TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments and remand the matter back to TCEQ for further proceedings. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before 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 have filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to SOAH for further proceedings. 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.

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On December 1, 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 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 allege 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 on June 13, 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 on May 21, 2007. The Plaintiffs have appealed the District Court’s dismissal of the case to the Fifth Circuit Court of Appeals and oral argument was heard in the appeal on March 3, 2008. EFH Corp. believes the District Court properly granted the Motion to Dismiss and while EFH Corp. is unable to estimate any possible loss or predict the outcome of this litigation in the event the Fifth Circuit Court of Appeals reverses the District Court, EFH Corp. maintains that the claims made in the complaint are without merit. Accordingly, EFH Corp. intends to vigorously defend the appeal and this litigation in the event the Fifth Circuit reverses the District Court.

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 have appealed the district court’s decision to the Fifth Circuit Court of Appeals. There can be no assurance that the outcome of this matter would not result in an adverse impact on the Sandow 5 project. EFH Corp. believes the claims on appeal are without merit and will vigorously defend the appeal.

Litigation – Other

On September 6, 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. 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 on August 30, 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 which is pending before the District Court. 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, including the appeal of the District Court’s order dismissing the litigation.

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In November 2002, February 2003 and March 2003, three lawsuits were filed in the US District Court for the Northern District of Texas, Dallas Division, asserting claims under Employee Retirement Income Security Act (ERISA) on behalf of a putative class of participants in and beneficiaries of various employee benefit plans of EFH Corp. (then known as TXU Corp.). These ERISA lawsuits were consolidated, and a consolidated complaint was filed in February 2004 against EFH Corp., former directors of EFH Corp. serving during the putative class period as well as certain officers of EFH Corp. who were the members of the EFH Thrift Plan Committee. The plaintiffs seek to represent a class of participants in such employee benefit plans during the period between April 26, 2001 and October 11, 2002. The plaintiffs filed an initial motion for class certification and, after class certification discovery was completed, the District Court denied plaintiffs’ initial class certification motion without prejudice and granted plaintiffs’ leave to amend their complaint. Plaintiffs’ second class certification motion, filed on the basis of their amended complaint, was denied, and the case was ordered dismissed without prejudice on September 29, 2005. The plaintiffs filed an appeal of the dismissal to the Fifth Circuit Court of Appeals. While on appeal, the matter was referred to the Fifth Circuit’s alternative dispute resolution program and subsequently to mediation. While mediation was unsuccessful, further discussions led to an agreement in principle to settle this litigation on December 24, 2006 for $7.25 million, before attorneys’ fees, to be paid by EFH Corp. to the Thrift Plan pursuant to a Court approved allocation. A Memorandum of Understanding confirming the agreement in principle was signed on January 24, 2007, a final settlement agreement was signed in September 2007 and the court entered an Order Granting Preliminary Approval of the settlement on December 12, 2007. On March 25, 2008, the District Court entered an order approving the settlement as well as a final judgment. No objections to the settlement were filed. Accordingly, EFH Corp. does not expect an appeal.

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.

Regulatory Investigations

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 is 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. A hearing requested by Luminant Energy to contest the alleged occurrence of a violation and the amount of the penalty in the NOV was scheduled to start in April 2008 but was stayed pending resolution of discovery disputes and Luminant Energy’s motion to dismiss, which was filed in November 2007. That motion was denied by the state administrative law judges, and in February 2008 the PUCT declined to hear Luminant Energy’s appeal of that denial. On March 26, 2008, Luminant Energy submitted to the administrative law judges its motion for summary decision on the discrete legal issue of what the maximum lawful penalty calculation could be in this proceeding. EFH Corp. believes Luminant Energy’s conduct during the period in question was consistent with the PUCT’s rules and policies, and no market power abuse was committed. EFH Corp. is vigorously contesting the NOV. EFH Corp. is unable to predict the outcome of this matter.

EFH Corp. and Luminant Energy have taken actions to reduce the risk of future similar allegations related to the balancing energy segment of the ERCOT wholesale market, including working with the PUCT Staff and the PUCT’s independent market monitor to develop a voluntary mitigation plan for approval by the PUCT. Luminant Energy has submitted a voluntary mitigation plan that was approved by the PUCT in July 2007. The PUCT’s approval action was challenged by some other market participants on procedural grounds, and a Texas District Court upheld that challenge. The PUCT did not appeal that ruling.

In addition to the above, EFH Corp. is involved in various other regulatory investigations 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.

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

None.

PART II

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

In connection with the closing of the Merger, EFH Corp.’s common stock was converted into the right to receive $69.25 per share, and it requested that each of the New York Stock Exchange and the Chicago Stock Exchange file with the Securities and Exchange Commission an application on Form 25 to remove the common stock from listing and registration thereon. In October 2007, each of the New York Stock Exchange and the Chicago Stock Exchange confirmed that such filing had been made. 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.

In February 2007, EFH Corp.’s board of directors declared a common stock dividend of 43.25 cents per share that was paid on April 2, 2007 to shareholders of record as of March 2, 2007. In May 2007, EFH Corp.’s board of directors declared a common stock dividend of 43.25 cents per share that was paid on July 2, 2007 to shareholders of record as of June 1, 2007. In August 2007, EFH Corp.’s board of directors declared a common stock dividend of 43.25 cents per share that was paid on October 1, 2007 to shareholders of record as of September 7, 2007. EFH Corp. did not declare a quarterly dividend during the fourth quarter of 2007. 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.

Distributions paid on EFH Corp.’s common stock in 2007 were reported to the US Internal Revenue Service (IRS) and to shareholders as nontaxable distributions in accordance with IRS rules.

The number of holders of the common stock of EFH Corp. as of March 25, 2008 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
	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			2003
Operating revenues	$	502		$	7,490		$	10,856		$	10,662		$	9,216		$	8,532
Income (loss) from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles		(1,361	)		699		$	2,465		$	1,775		$	81		$	566
Income from discontinued operations, net of tax effect		1			24		$	87		$	5		$	378		$	74
Extraordinary gain (loss), net of tax effect		—			—		$	—		$	(50	)	$	16		$	—
Cumulative effect of changes in accounting principles, net of tax effect		—			—		$	—		$	(8	)	$	10		$	(58	)
Exchangeable preferred membership interest buyback premium		—			—		$	—		$	—		$	849		$	—
Preference stock dividends		—			—		$	—		$	10		$	22		$	22
Net income (loss) available for common stock		(1,360	)		723		$	2,552		$	1,712		$	(386	)	$	560
Ratio of earnings to fixed charges (a)		—			2.30			5.11			3.80			1.16			1.94
Ratio of earnings to combined fixed charges and preference dividends (a)		—			2.30			5.11			3.74			1.11			1.87
Embedded interest cost on long-term debt — end of period (b)		9.5	%		6.5	%		6.6	%		6.3	%		6.0	%		6.3	%
Embedded dividend cost on preferred stock of subsidiaries — end of period (c)		—	%		—	%		—	%		—	%		4.4	%		9.7	%
Capital expenditures	$	684		$	2,341		$	2,180		$	1,047		$	912		$	721
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, 2007			December 31,
				2006			2005			2004			2003
Total assets — end of year	$	63,784		$	25,833		$	25,539		$	23,189		$	31,284
Property, plant & equipment — net — end of year	$	28,650			18,569			17,006			16,495			16,432
Capitalization — end of year
Equity-linked debt securities	$	—		$	—		$	179		$	285		$	1,440
Long-term debt held by subsidiary trusts		—			—			—			—			546
All other long-term debt, less amounts due currently		38,603			10,631			11,153			12,127			9,168
Exchangeable preferred membership interests (d)		—			—			—			—			646
Preferred stock of subsidiaries (not subject to mandatory redemption) (e)		—			—			—			38			113
Preference stock		—			—			—			300			300
Common stock equity		6,685			2,140			475			339			5,619
Total	$	45,288		$	12,771		$	11,807		$	13,089		$	17,832
Capitalization ratios — end of year
Equity-linked debt securities		—	%		—	%		1.5	%		2.2	%		8.1	%
Long-term debt held by subsidiary trusts		—			—			—			—			3.1
All other long-term debt, less amounts due currently		85.2			83.2			94.5			92.6			51.4
Exchangeable preferred membership interests (d)		—			—			—			—			3.6
Preferred stock of subsidiaries (e)		—			—			—			0.3			0.6
Preference stock		—			—			—			2.3			1.7
Common stock equity		14.8			16.8			4.0			2.6			31.5
Total		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
Notes payable — commercial paper	$	—		$	1,296		$	358		$	—		$	—
Notes payable — banks		1,718			195			440			210			—
Long-term debt due currently		513			485			1,250			229			678

(a) For the period from October 11, 2007 through December 31, 2007, fixed charges and combined fixed charges and preference dividends exceeded earnings by $2.034 billion.

(b) Represents the annual interest using year-end rates for variable rate debt and reflecting the effects of interest rate swaps 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.

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

(d) Amount is net of discount.

(e) Preferred stock outstanding at the end of 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 period 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/A for the year ended December 31, 2006 with the exception of the adoption of FIN 48. The consolidated financial statements of the Successor reflect the application of “purchase accounting”.

Note: 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 other 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.

	Predecessor (a)							Successor
	First Quarter			Second Quarter		Third Quarter		Period from October 11, 2007 through December 31, 2007
2007:
Operating revenues	$	1,669		$	2,022	$	3,445	$	502
Income (loss) from continuing operations		(497	)		110		979		(1,361	)
Income from discontinued operations, net of tax effect		—			11		13		1
Net income (loss) available for common stock	$	(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.

	Predecessor
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2006:
Operating revenues	$	2,304	$	2,667	$	3,510	$	2,375
Net income from continuing operations available for common stock		516		497		984		469
Income from discontinued operations, net of tax effect		60		—		20		6
Net income available for common stock	$	576	$	497	$	1,004	$	475

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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, 2007, 2006 and 2005 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. (formerly TXU 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 Luminant, which is engaged in electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases, and commodity risk management and trading activities, and TXU Energy, which is engaged in retail electricity sales. Oncor is engaged in regulated electricity transmission and distribution operations in Texas.

As part of the Merger, to enhance the separateness between the Oncor Ring-Fenced Entities and the Texas Holdings Group, various legal, financial and contractual provisions were implemented. Such “ring-fencing” measures included, among other things: TXU Electric Delivery Company’s name change to Oncor Electric Delivery Company; 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; physical separation of Oncor’s headquarters from the Luminant entities and TXU Energy; amendments to contracts between the Oncor Ring-Fenced Entities and the Texas Holdings Group, 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, including TXU Energy and the Luminant entities, 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. See “Stipulation Approved by the PUCT” under “Regulations and Rates” below.

EFH Corp. currently intends to sell a 20% minority stake in Oncor to further enhance Oncor’s separation from the Texas Holding Group. The purchaser of the minority stake will not be affiliated with any member of the Sponsor Group, Texas Holdings or EFH Corp.

In connection with the Merger, certain of the subsidiaries of EFH Corp. established for the purpose of developing and constructing new generation facilities (formerly referred to as TXU DevCo) have become subsidiaries of TCEH, and certain assets and liabilities of other of these subsidiaries that did not become subsidiaries of TCEH were transferred to TCEH and its subsidiaries. Those subsidiaries holding impaired construction work-in-process assets (see Note 7 to Financial Statements) have not become subsidiaries of TCEH. In addition, a wholly-owned subsidiary of EFC Holdings representing a lease trust holding certain combustion turbines has become a subsidiary of TCEH.

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Operating Segments

EFH Corp. has aligned and reports its business activities as two operating segments: the Competitive Electric segment (formerly the TXU Energy Holdings segment) and the Regulated Delivery segment (formerly the Oncor Electric Delivery segment).

The Competitive Electric segment includes the activities of TCEH, as described above, as well as equipment salvage and resale activities related to eight canceled 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 revenues and costs associated with installation of equipment for a third party that will facilitate Oncor’s technology initiatives designed to improve system reliability and support advanced metering.

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

Significant Developments

Merger— As a result of the Merger, EFH Corp. became a subsidiary of Texas Holdings. The outstanding shares of common stock of EFH Corp. were converted into the right to receive $69.25 per share. Texas Holdings is controlled by investment funds affiliated with the Sponsor Group.

The aggregate purchase price paid for the equity securities of EFH Corp. was $31.9 billion, which purchase price was funded by $8.3 billion of equity financing from the Sponsor Group and by the debt financings described in Note 17 to Financial Statements. This purchase price is exclusive of $0.8 billion in costs directly associated with the Merger, consisting of legal, consulting and professional service fees incurred by the Sponsor Group. See Note 1 to Financial Statements for additional details regarding the completion of the Merger.

The Merger was recorded 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 the net assets was recorded as goodwill. The allocation resulted in $23.0 billion of goodwill and $10.0 billion in increased or new net tangible and identifiable intangible assets. Immediately following the closing of the Merger, EFH Corp. had total debt (short-term borrowings and long-term debt, including amounts due currently) of $40.6 billion. Interest expense and related charges are expected to total approximately $3.8 billion in 2008, taking into account interest rate swaps relating to $15.05 billion of EFH Corp.’s debt. Additionally, reflecting a net increase in the carrying value of generation plants and the recording of identifiable intangible assets, depreciation and amortization expense is expected to total approximately $1.6 billion in 2008.

Texas Generation Facilities Development —Luminant is developing three lignite-fueled generation units in the state of Texas with a 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/coal-fueled generation plant site (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. Design and procurement activities for the three units are essentially complete and construction is well underway. Air permits for all three units have been obtained. EPC agreements have been executed with EPC contractors to engineer and construct the Sandow and Oak Grove units. 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 $1.7 billion was incurred as of December 31, 2007. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $5.0 billion. The expected commercial operation dates of the units are as follows: Sandow in 2009 and Oak Grove’s two units in 2009 and 2010. See discussion in Note 18 to Financial Statements under “Generation Development” regarding actions taken by opponents of the new units.

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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 includes an environmental retrofit program under which Luminant will install additional environmental control systems at its existing generation facilities. Estimated capital expenditures associated with these additional environmental control systems total approximately $1 billion to $1.3 billion. Luminant has not yet completed detailed cost and engineering studies for the additional environmental systems, and the cost estimates could materially change as Luminant determines the details of and further evaluates the engineering and construction costs related to these investments.

See discussion in Note 7 to Financial Statements related to the net charges resulting from the cancellation of development of eight coal-fueled generation facilities in Texas. In October 2007, EFH Corp. formally acted to terminate air permit applications for eight coal-fueled generation units, fulfilling the commitment to terminate the permit process upon close of the Merger.

Retail Pricing— In May 2007, EFH Corp. and the Sponsor Group announced that residential price cuts provided by TXU Energy would total 15%, which represented a five percentage point increase over the previously announced price discount program. Accordingly, residential customers under qualifying service plans received a 6% price reduction in March 2007, an additional 4% reduction in June 2007 and a 5% reduction in October 2007.

Long-Term Hedging Program — In October 2005, EFH Corp. initiated 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 March 14, 2008, these subsidiaries have effectively sold forward approximately 2.4 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 305,000 GWh at an assumed 8.0 MMBtu/MWh market heat rate) over the period from 2008 to 2013 at average annual prices ranging from $7.25 per MMBtu to $8.15 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 2008 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 84% of its expected baseload generation natural gas price exposure for such period (on an average basis for such period).

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 March 14, 2008, a $1.00/MMBtu change in natural gas prices would result in the recognition by EFH Corp. of approximately $2.4 billion in pretax unrealized mark-to-market gains or losses.

Unrealized mark-to-market losses associated with the long-term hedging program were significant in 2007 (approximately $2 billion) and are expected to be significant in the early part of 2008 as upward pressure on forward natural gas prices has continued. Given the volatility of natural gas prices, the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in future years are not possible to predict. The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices. 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. Based on fair values of the positions, these hedging transactions were $1.8 billion out-of-the-money at December 31, 2007 due to higher forward natural gas prices. Reflective of the volatility of forward natural gas prices, this out-of-the-money position increased to $4.4 billion by March 14, 2008 and then decreased to $2.3 billion by March 21, 2008. These values can change materially as market conditions change.

In the 2007 Predecessor period, subsidiaries of EFH Corp. entered into several large hedging transactions involving natural gas-related financial instruments that resulted in “day one” losses totaling $227 million. In the 2007 Successor period, subsidiaries of EFH Corp. entered into a large hedging transaction involving natural gas-related financial instruments that resulted in a “day one” loss totaling $8 million. The “day one” losses essentially represent the cost to transact these positions given their size and long dating.

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As of March 14, 2008, approximately 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 of the hedging program.

Interest Rate Hedges— In the 2007 Successor period, TCEH entered into a series of interest rate swap transactions that effectively fixed the interest rates at between 7.3% and 8.3% on $15.05 billion principal amount of its senior secured debt maturing from 2009 to 2014. Taking into consideration these swap transactions, approximately 13% of EFH Corp.’s total long-term debt portfolio at December 31, 2007 is exposed to variable interest rate risk. Based on the fair value of the positions, the interest rate swaps were $280 million out-of-the-money at December 31, 2007 and $845 million out-of-the-money at February 29, 2008 due to lower market interest rates. These fair values can change materially as market conditions change. See Note 17 to Financial Statements for additional discussion of these swaps.

Oncor Regulatory Developments— See discussion below under “Regulations and Rates” for additional information regarding the following items:

• the final order entered by the PUCT in February 2008, among other things, approves Oncor’s commitment to file a rate case in no later than July 1, 2008, based on a test year ended December 31, 2007;

• Oncor’s intention to file a surcharge request on or before July 1, 2008 to request recovery of its estimated future investment for advanced metering deployment, and

• Oncor’s interest in constructing designated transmission facilities in Competitive Renewable Energy Zones.

Termination of New Utility Services Joint Venture — In connection with the Merger, EFH Corp. and Oncor terminated their previously proposed InfrastruX Energy Services joint venture for utility infrastructure and management services and the related utility services agreement. Accordingly, in 2007 (prior to the Merger), EFH Corp. wrote-off approximately $12 million ($8 million after-tax) in previously deferred costs primarily representing professional fees incurred in the development of the joint venture agreements.

Nuclear Generation Development — EFH Corp. is proceeding with the preparation of a combined license application for two new nuclear generation facilities, each with approximately 1,700 MW (gross capacity), at its existing Comanche Peak nuclear generation site. It is currently anticipated that these new units would be developed by TCEH or its subsidiaries.

Investment in Cleaner Coal-Fueled Generation Technologies— In an initiative separate from but related to the generation development and related emissions controls program, subsidiaries of TCEH expect to invest over the next five to seven years in the development and commercialization of cleaner generation plant technologies. Luminant has initiated a number of actions, including research and development investments to advance next-generation emissions reduction technologies. Additionally, in December 2007, EFH Corp. issued a request for proposals for the potential development of two IGCC commercial demonstration facilities with carbon dioxide capture in Texas, and 14 expressions of interest were received. Detailed proposals are due by June 2008. Luminant will undertake a detailed evaluation of proposals received before deciding whether to proceed with preliminary engineering designs for these facilities.

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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.

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. Natural gas prices have increased significantly in recent years, but historically the price has fluctuated due to the effects of weather, changes in industrial demand and supply availability, and other economic and market factors. Wholesale electricity prices also move with market heat rates. Heat rate is the measure of the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity. The wholesale market price of power divided by the market price of natural gas represents the market heat rate.

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 70% of supply volumes in 2007, increase or decrease in value as natural gas prices 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. With the expiration of the regulatory price-to-beat rate mechanism on January 1, 2007 (see discussion below under “Regulation and Rates”), TXU Energy has price flexibility in all of its retail markets.

Considering current and forecasted electricity supply and sales load and wholesale market positions, EFH Corp.’s portfolio position for 2008 is largely balanced with respect to changes in natural gas prices. The supply and load forecast take into account projections of baseload unit availability and customer churn and retail sales.

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 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 risk, and

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

As discussed above under “Significant Developments”, 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 scenarios are presented to quantify the potential impact of movements in natural gas prices and market heat rates. Illustratively, if TXU Energy’s sales prices immediately and fully adjusted to reflect changes in wholesale electricity prices due to changes in natural gas prices, and taking into account the hedges in place at year-end 2007 under the long-term hedging program expected to settle in 2008, EFH Corp. could experience an approximate $170 million reduction in 2008 pretax earnings for every $1.00 per MMBtu reduction in natural gas prices (approximate 13% change in current price) sustained over the full year. In the same scenario of full and immediate pass-through of wholesale electricity price changes to sales prices, where natural gas prices and other nonprice conditions remained unchanged but ERCOT wholesale electricity prices declined by $5/MWh (approximate 8% change in current price) for a full year because of a decline in market heat rates, EFH Corp. could experience an approximate $260 million reduction in 2008 pretax earnings.

The long-term hedging program does not mitigate exposure to changes in market heat rates. 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, 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.

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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, or the unwinding of existing transactions or 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 Disclosure about Market Risk.”

Competitive Markets and Customer Retention

Competitive retail activity in Texas continued to result in declines in sales volumes in EFH Corp.’s historical service territory. Total retail sales volumes declined 5%, 11% and 17% in 2007, 2006 and 2005, 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. The area representing EFH Corp.’s historical service territory prior to deregulation, largely in north Texas, consisted of more than 3 million electricity consumers (measured by meter counts) as of year-end 2007. TXU Energy currently has approximately 1.8 million retail customers in that territory and has acquired approximately 346,000 retail customers in other competitive areas in Texas. In responding to the competitive landscape and full competition in the ERCOT marketplace since January 1, 2007, TXU Energy is focusing on the following key initiatives:

• TXU Energy has introduced competitive pricing initiatives as evidenced by the 15% cumulative price reduction applicable to residential customers under qualifying service plans;

• 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 delivering world-class customer service and improving the overall customer experience. In line with this strategy, TXU Energy continues to implement initiatives to improve customer service;

• TXU Energy intends to establish itself as the most innovative retailer in the Texas market as it is critical in the fully competitive environment and continues 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 help reduce peak demand for electricity; and

• Initiatives in the business market are focused largely on programs targeted to retain the existing highest-value customers and to recapture customers who have switched REPs. Initiatives include a more disciplined contracting and pricing approach and improved 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.

Substantial Leverage, Uncertain Financial Markets and Liquidity Risk

EFH Corp.’s substantial leverage, resulting in part from debt incurred to finance the Merger, will require a substantial amount of cash flow to be dedicated to principal and interest payments and could adversely affect its ability to raise additional capital to fund operations, limit its ability to react to changes in the economy or its industry, expose it to interest rate risk to the extent of its variable rate debt and limit its ability to meet its obligations. Total debt (representing short-term borrowings and long-term debt, including amounts due currently) at December 31, 2007 was $40.8 billion. In 2008, annual interest expense and related charges are expected to total approximately $3.8 billion. Taking into consideration interest-rate swap transactions as of December 31, 2007, approximately 13% of EFH Corp.’s total long-term debt portfolio is exposed to variable interest rate risk. Principal payments on EFH Corp.’s debt in 2008 are expected to total approximately $468 million.

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While EFH Corp. believes its cash flow from operations combined with availability under existing credit facilities provide sufficient liquidity to fund current obligations, projected working capital requirements and capital spending for 2008 (see “Liquidity and Capital Resources” section below), there can be no assurance that, considering the current uncertainty in financial markets, counterparties to the credit facilities will perform as expected or that substantial unexpected changes in financial markets, the economy, the requirements of regulators or EFH Corp.’s industry or operations will not result in liquidity constraints.

Texas Generation Development Program

The undertaking of the development of three generation facilities in Texas as described above under “Significant Developments” 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 CO₂ emissions regulation may prove to be inaccurate, and returns on the investment could be significantly less than anticipated. The program is exposed to construction delays, failure of the units to meet performance specifications, nonperformance by equipment suppliers, increases in construction labor costs (contractually limited in part) and other project execution risks. Further, project capital spending for the three units continues despite continued public discussion of the advantages and disadvantages of coal-fueled generation. Should these development activities be canceled, EFH Corp. is exposed to impairment of construction work-in-process assets and project discontinuance costs, including equipment order cancellation penalties (see Note 7 to Financial Statements). Management has evaluated the potential risks and benefits of the program to both Texas consumers and EFH Corp. and believes that in consideration of the most likely market and performance scenarios, continued progress towards completion of the program is the appropriate course of action.

Energy Prices and Regulatory Risk

Natural gas prices rose to unprecedented levels in the latter part of 2005, reflecting a world-wide increase in energy prices compounded by hurricane-related infrastructure damage. The related rise in retail electricity prices elevated public awareness of energy costs and dampened customer demand in 2006 and 2007. Natural gas prices remain subject to events that create price volatility, and while not at 2005 levels, forward natural gas prices have risen substantially since the end of 2006. 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 that regulatory bodies 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 wholesale electricity prices, which could negatively impact results of EFH Corp.’s long-term hedging strategy.

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.

EFH Corp. continues to closely monitor any potential legislative changes pertaining to climate change and CO₂ emissions. The increasing attention to potential environmental effects of greenhouse gas emissions creates risk as to the economics of EFH Corp.’s program to develop new coal-fueled generation facilities in Texas. New legislation could result in higher costs due to new taxes, the need to acquire emissions credits or capital spending to reduce CO₂ emissions. EFH Corp. believes that any legislative actions to reduce greenhouse gas emissions should be developed under a market-based framework that is consistent with expected technology development timelines and supports the displacement of old, inefficient electricity generation technology with advanced, more efficient and cleaner-emitting technology.

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EFH Corp. has announced actions to address CO₂ emissions concerns, including:

• Investing in the development and commercialization of cleaner generation plant technologies;

• Initiating the process to file an application to the NRC for licenses to construct and operate a new nuclear generation facility in Texas;

• Doubling the renewable energy (wind generation) portfolio from 2006 levels to 1,500 MW;

• Investing $400 million over the five years beginning in 2008 in programs designed to encourage customer electricity demand efficiencies, and

• Increasing production efficiency of its existing generation facilities by up to 2 percent.

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 $3.5 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 18 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.

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 has been 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. Such assumptions and judgments that would be appropriate at the acquisition date may prove to be incorrect if market conditions change.

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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 have been 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 totaled $23.0 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 $18.1 billion to the Competitive Electric segment and $4.9 billion to the Regulated Delivery segment. Also see discussion below under “Impairment of Long-Lived Assets”.

The purchase price allocation at December 31, 2007 is substantially complete; however, additional analysis with respect to the value of certain assets, contractual arrangements, contingent liabilities and debt could result in a change in the total amount of goodwill and amounts assigned to EFH Corp.’s reporting units. See Note 2 to Financial Statements for details of the purchase price allocation.

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.

SFAS 133 allows for “normal” purchase or sale elections and hedge accounting designations, which generally eliminates or defers the requirement for mark-to-market recognition in net income and thus reduces the volatility of net income that can result from fluctuations in fair values. These elections and designations are intended to better match the accounting recognition of the contract’s financial performance with the economic and risk decision-making profile. “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 are initially recorded in other comprehensive income and 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. See further discussion of the long-term hedging program above under “Significant Developments”.

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.

	Combined (a)			Successor			Predecessor
	Year Ended December 31, 2007			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31,
										2006			2005
Amounts recognized in net income (after-tax):
Unrealized net gains (losses) on unsettled positions marked-to-market in net income	$	(1,481	)	$	(959	)	$	(522	)	$	15		$	21
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the period		(58	)		(52	)		(6	)		7			(15	)
Unrealized ineffectiveness net gains (losses) on unsettled positions accounted for as cash flow hedges		74			—			74			141			(24	)
Reversals of previously recognized unrealized net (gains) losses related to cash flow hedge positions settled in the period		(15	)		—			(15	)		14			7
Total	$	(1,480	)	$	(1,011	)	$	(469	)	$	177		$	(11	)
Amounts recognized in other comprehensive income (after-tax):
Net gains (losses) in fair value of unsettled positions accounted for as cash flow hedges	$	(425	)	$	(177	)	$	(248	)	$	568		$	(47	)
Net (gains) losses on cash flow hedge positions recognized in net income to offset hedged transactions		(129	)		—			(129	)		(15	)		77
Total	$	(554	)	$	(177	)	$	(377	)	$	553		$	30

(a) Combined results for the year ended December 31, 2007 represent the mathematical sum of the Predecessor period from January 1, 2007 through October 10, 2007 and the Successor period from October 11, 2007 through December 31, 2007. This presentation does not comply with GAAP or the rules for pro forma presentation, but is presented because management believes it is the most meaningful comparison of the results. Such presentation is not an indication of future results. See “Presentation and Analysis of Results” below.

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

	Successor			Predecessor
	December 31, 2007			December 31, 2006
Net derivative asset related to commodity cash flow hedges	$	7		$	910
Net derivative liability related to interest rate cash flow hedges		(280	)		—
Net derivative liability related to interest rate fair value hedges		(36	)		(85	)
Other derivative assets		—			9
Total net cash flow hedge and other derivative asset (liability)	$	(309	)	$	834
Net commodity contract asset (liability) (a)	$	(2,009	)	$	69
Long-term debt fair value adjustments — decrease in carrying value	$	—		$	(63	)
Net accumulated other comprehensive gain (loss) included in shareholders’ equity (after-tax) amounts (b)	$	(177	)	$	411

(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.

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 $477 million, $466 million and $494 million at December 31, 2007, 2006 and 2005, respectively.

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 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 collectibility of accounts receivable. Bad debt expense totaled $13 million, $46 million, $68 million and $56 million for the period from October 11, 2007 to December 31, 2007, the period from January 1, 2007 to October 10, 2007, and the years ended December 31, 2006 and 2005, respectively.

Litigation contingencies also may require significant judgment in estimating amounts to accrue. During 2004, management assessed the progress and status of matters in litigation and recorded a net $84 million ($55 million after-tax) charge for the anticipated settlement of certain shareholders’ litigation initially filed in October 2002 (estimated litigation liability of $150 million less $66 million in pledged reimbursements from insurance carriers). In 2005, EFH Corp. reached a comprehensive settlement of this litigation, which included a one-time payment to the class members of $150 million. To recognize additional insurance reimbursements related to the settlement, EFH Corp. recorded credits to earnings of $35 million ($23 million after-tax) in 2005, $15 million ($10 million after-tax) in 2006, $37 million ($24 million after-tax) in the period of January 1, 2007 to October 10, 2007 and $2 million ($1 million after-tax) in the period of October 11, 2007 to December 31, 2007.

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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 12 to the Financial Statements, EFH Corp. adopted this new standard January 1, 2007, as required. Also, see Notes 1 and 14 to Financial Statements for discussion of income tax matters.

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 SFAS 144. One of those indications is a current expectation that “more likely than not” a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. For 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 lives are required to be tested for impairment at least annually or whenever 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 lives for impairment on October 1st each year.

In 2006, EFH Corp. recorded an impairment charge of $198 million ($129 million after-tax) related to its natural gas-fueled generation units. See Note 8 to Financial Statements for a discussion of the impairment. The estimated impairment was based on numerous judgments including forecasted production, forward prices of natural gas and electricity, overall generation availability in ERCOT and ERCOT grid congestion.

In 2007 EFH Corp. recorded a net charge totaling $756 million ($491 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 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 7 to Financial Statements for additional discussion.

Depreciation and Amortization

Subsequent to the Merger, 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.

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The estimated remaining lives range from 25 to 34 years for the lignite/coal-fueled generation units and an average 44 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. Depreciation expense for the entire generation fleet is expected to total approximately $1.014 billion in 2008, an increase of $694 million over the annualized 2007 pre-Merger expense amount, reflecting the effects of the increased values pursuant 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 discussed above, transmission and distribution utility assets subject to regulated rate recovery were not subject to revaluation in purchase accounting. Depreciation expense for such assets totaled $298 million, $301 million and $283 million in 2007, 2006 and 2005, or 2.8% of carrying value in each of 2007, 2006 and 2005.

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, 2007 and 2006, reflect total regulatory assets of $1.593 billion and $2.161 billion, respectively. These amounts include $967 million and $1.316 billion, 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 in the regulatory rate case to be filed by Oncor in 2008 totaled $446 million at December 31, 2007. These amounts consist primarily of employee retirement costs (see Note 22 to Financial Statements) and storm-related service recovery costs. See Note 28 to Financial Statements for information about certain regulatory asset amounts for which Oncor is not seeking recovery.

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 OPEBs 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
	Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			December 31,
							2006			2005
Pension costs under SFAS 87	$	(1	)	$	34		$	66		$	46
OPEB costs under SFAS 106		11			49			81			71
Total benefit costs	$	10		$	83		$	147		$	117
Less amounts deferred principally as a regulatory asset or property		(8	)		(43	)		(84	)		(58	)
Net amounts recognized as expense	$	2		$	40		$	63		$	59

Detailed information regarding EFH Corp.’s pension and OPEB costs is provided in Note 22 to Financial Statements. Additional information regarding pension and OPEB plans is as follows:

• Pension and OPEB costs decreased $54 million to $93 million in 2007 driven by cost-saving measures that resulted in a significant decrease in expected medical claims that in turn reduced the OPEB liability calculations, a higher discount rate (5.90% from January 1, 2007 through October 10, 2007 and 6.45% from October 11, 2007 through December 31, 2007 versus 5.75% in 2006) and the absence of reclassification of amounts from accumulated other comprehensive income to net income in the 2007 Successor period due to purchase accounting. Pension and OPEB costs increased $30 million to $147 million in 2006 primarily due to a lower discount rate (5.75% in 2006 versus 6.00% in 2005) used to measure pension and OPEB obligations.

See Note 22 to Financial Statements regarding discount rates for pension and OPEB obligations.

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

Assumption	Increase/(decrease) in 2007 Pension and OPEB Costs
Discount rate – 1% increase	$	(15	)
Discount rate – 1% decrease	$	14
Expected return on assets – 1% increase	$	(24	)
Expected return on assets – 1% decrease	$	24

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.

50

PRESENTATION AND ANALYSIS OF RESULTS

Although EFH Corp. continued as the same legal entity after the Merger, the accompanying statements of consolidated income and cash flows for 2007 are presented for two periods: January 1, 2007 through October 10, 2007 (Predecessor) and October 11, 2007 through December 31, 2007 (Successor), which relate to the period before the Merger and the period after the Merger, respectively. Management’s discussion and analysis of results of operations and cash flows for the year ended December 31, 2007 has been prepared by comparing the results of operations and cash flows of the Predecessor for the year ended December 31, 2006 to the combined amounts obtained by adding the Predecessor’s results of operations and cash flows for the period January 1, 2007 through October 10, 2007 to the Successor’s results of operations and cash flows for the period October 11, 2007 through December 31, 2007. Although this combined presentation does not comply with GAAP and the results of operations of the Predecessor and Successor are not comparable due to the change in basis resulting from the Merger, management uses this approach for its own analysis and believes it results in the most meaningful analysis of changes in the results of operations. Such presentation is not an indication of future results. Key drivers in the results of operations for the Successor and/or Predecessor periods will be discussed in more detail.

RESULTS OF OPERATIONS

Results of operations and the related management’s discussion of those results for all periods presented reflect the discontinuance of certain operations (see Note 4 to Financial Statements regarding discontinued operations).

EFH Corp. Consolidated Financial Results–2007 compared to 2006

	Combined (a)			Successor			Predecessor
	Year Ended December 31, 2007			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	$	7,992		$	502		$	7,490		$	10,856
Costs and expenses:
Fuel, purchased power costs and delivery fees		3,025			644			2,381			2,784
Operating costs		1,413			306			1,107			1,373
Depreciation and amortization		1,049			415			634			830
Selling, general and administrative expenses		907			216			691			819
Franchise and revenue-based taxes		375			93			282			390
Other income		(83	)		(14	)		(69	)		(121	)
Other deductions		902			61			841			269
Interest income		(80	)		(24	)		(56	)		(46	)
Interest expense and related charges		1,510			839			671			830
Total costs and expenses		9,018			2,536			6,482			7,128
Income (loss) from continuing operations before income taxes, extraordinary loss and cumulative effect of changes in accounting principles		(1,026	)		(2,034	)		1,008			3,728
Income tax expense (benefit)		(364	)		(673	)		309			1,263
Income (loss) from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles		(662	)		(1,361	)		699			2,465
Income from discontinued operations, net of tax effect		25			1			24			87
Net income (loss) available for common stock	$	(637	)	$	(1,360	)	$	723		$	2,552

(a) Combined results for the year ended December 31, 2007 represent the mathematical sum of the Predecessor period from January 1, 2007 through October 10, 2007 and the Successor period from October 11, 2007 through December 31, 2007. This presentation does not comply with GAAP or the rules for pro forma presentation, but is presented because management believes it is the most meaningful comparison of the results. Such presentation is not an indication of future results. See “Presentation and Analysis of Results” above.

51

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.

EFH Corp.’s operating revenues decreased $2.864 billion, or 26%, to $7.992 billion in 2007 as shown in the table below:

	Combined (a)			Successor			Predecessor
	Year Ended December 31, 2007			Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Competitive Electric segment:
Total retail electricity revenues	$	6,156		$	1,142		$	5,014		$	6,953
Accrued customer appreciation bonus		—			—			—			(162	)
Wholesale electricity revenues		2,142			505			1,637			2,278
Wholesale balancing activities		(23	)		(9	)		(14	)		(31	)
Results of risk management and trading activities		(2,046	)		(1,492	)		(554	)		153
Amortization of intangibles (b)		(50	)		(50	)		—			—
Other operating revenues		330			83			247			358
Total Competitive Electric segment		6,509			179			6,330			9,549
Regulated Delivery segment		2,519			532			1,987			2,449
Net intercompany eliminations		(1,036	)		(209	)		(827	)		(1,142	)
Total consolidated revenues	$	7,992		$	502		$	7,490		$	10,856

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP presentation.

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

• Operating revenues in the Competitive Electric segment decreased $3.040 billion, or 32%, to $6.509 billion. The decrease reflected a $2.199 billion unfavorable change in results from risk management and trading activities and a $797 million decrease in retail electricity revenues. The change in results from risk management and trading activities was driven by unrealized mark-to-market losses on positions in the long-term hedging program due to an increase in forward market prices of natural gas. Also see discussion above under “Long-Term Hedging Program”. The decrease in retail electricity revenues reflected 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 $70 million, or 3%, to $2.519 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, which resulted in a decline in total delivered volumes.

• A decrease in the net intercompany sales elimination of $106 million reflected lower sales by Oncor to REP subsidiaries of TCEH, while its sales to nonaffiliated REPs increased.

52

Gross Margin

	Combined (a)				Successor			Predecessor
	Year Ended December 31, 2007		% of Revenue		Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007		Year Ended December 31, 2006		% of Revenue
Operating revenues	$	7,992	100	%	$	502		$	7,490	$	10,856	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees (b)		3,025	38			644			2,381		2,784	26
Operating costs		1,413	18			306			1,107		1,373	13
Depreciation and amortization of generation and delivery assets		951	12			330			621		813	7
Gross margin	$	2,603	32	%	$	(778	)	$	3,381	$	5,886	54	%

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP presentation.

(b) Includes $67 million of net amortization expense in the Successor period related to 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.

Gross margin is considered a key operating metric as its changes measure the effect of movements in sales volumes and pricing versus the variable and fixed costs to generate, purchase and deliver electricity.

Gross margin decreased $3.283 billion, or 56%, to $2.603 billion in 2007.

• The Competitive Electric segment’s gross margin decreased $3.318 billion, or 71%, to $1.371 billion, reflecting the decline in operating revenues, which was driven by unrealized losses on the long-term hedging program and lower retail pricing.

• The Regulated Delivery segment’s gross margin increased $34 million, or 3%, to $1.239 billion driven by higher transmission tariffs to recover ongoing investment in Oncor’s transmission system.

SG&A expenses increased $88 million, or 11%, to $907 million in 2007. The increase reflected:

• $35 million in increased retail marketing expenses;

• $27 million in higher professional fees including costs for retail billing and customer care systems enhancements and marketing/strategic/rebranding projects;

• $19 million in higher service provider fees primarily in the retail business, including effects of additional services and projects;

• $10 million in higher salary and benefits primarily driven by an increase in staffing in retail operations;

• $9 million in higher incentive compensation expense, and

• $8 million in management fees paid to the Sponsors,

partially offset by:

• $12 million in severance costs in 2006, and

• $10 million in lower bad debt expense driven by a decrease in delinquencies and lower accounts receivable balances.

53

Other income totaled $83 million in 2007 and $121 million in 2006. Other deductions totaled $902 million in 2007 and $269 million in 2006. The 2007 other deductions amount includes net charges of $757 million related to the canceled development of eight coal-fueled generation units ($755 million recorded in the Predecessor period — see Note 7 to Financial Statements). The 2006 other deductions amount includes a $198 million impairment charge related to natural gas-fired generation units (see Note 8 to Financial Statements). See Note 15 to Financial Statements for details of other income and deductions.

Interest expense and related charges increased $680 million, or 82%, to $1.510 billion in 2007 reflecting $517 million due to higher average borrowings, driven by the Merger-related financings, and $255 million in higher average interest rates, partially offset by $92 million in increased capitalized interest.

Income tax benefit on loss from continuing operations totaled $364 million in 2007 and income tax expense on income from continuing operations totaled $1.263 billion in 2006. The effective income tax rate was 35.5% on a loss in 2007 compared to 33.9% on income in 2006. The increased rate reflected the deferred tax impacts of the enactment of the Texas margin tax as described in Note 13 partially offset by higher interest accrued related to uncertain tax positions, higher Texas state taxes and the effect of non-deductible merger related transaction costs.

Results from continuing operations (an after-tax measure) decreased $3.127 billion to a loss of $662 million in 2007.

• Results in the Competitive Electric segment decreased $2.890 billion to a loss of $523 million driven by unrealized mark-to-market losses on positions in the long-term hedging program, the charges related to the canceled development of eight coal-fueled generation units, higher net interest expense, lower retail sales prices and the effects of purchase accounting.

• Results in the Regulated Delivery segment decreased $16 million, or 5%, to $328 million driven by higher costs associated with the 2006 cities rate settlement increased interest expense due primarily to higher average borrowings and increased operating costs, partially offset by higher transmission revenues.

• Corporate and Other net expenses totaled $467 million ($179 million in the Successor period) in 2007 and $246 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 $221 million primarily reflects (all amounts are after-tax):

^¡ a $77 million increase in net interest expense related to advances from subsidiaries reflecting higher balances and interest rates;

^¡ $59 million in financial advisory, legal and other professional fees in 2007 related to the Merger;

^¡ $26 million in higher accrued interest in 2007 related to uncertain income tax positions;

^¡ $25 million write-off in 2007 of 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;

^¡ $23 million tax effect in 2007 of nondeductible merger transaction costs;

^¡ a $17 million gain in 2006 related to the settlement of a telecommunications contract dispute;

^¡ a $10 million insurance recovery of a litigation settlement in 2006, and

^¡ $9 million in higher SG&A expenses in 2007 driven by a $5 million management fee paid to Sponsors,

partially offset by the $29 million deferred tax benefit in 2007 related to the Texas Margin tax as described in Note 13 to the Financial Statements.

54

EFH Corp. Consolidated Financial Results — 2006 compared to 2005

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.

EFH Corp.’s operating revenues increased $194 million, or 2%, to $10.856 billion in 2006 as shown in the table below:

	Predecessor
	Year Ended December 31,
	2006			2005			Increase (Decrease)
Competitive Electric segment:
Total retail electricity revenues	$	6,953		$	6,330		$	623
Accrued customer appreciation bonus		(162	)		—			(162	)
Wholesale electricity revenues		2,278			2,807			(529	)
Wholesale balancing activities		(31	)		225			(256	)
Results of risk management and trading activities		153			(164	)		317
Other operating revenues		358			354			4
Total Competitive Electric segment		9,549			9,552			(3	)
Regulated Delivery segment		2,449			2,394			55
Net intercompany eliminations		(1,142	)		(1,284	)		142
Total consolidated revenues	$	10,856		$	10,662		$	194

The following discusses the changes in revenue within the Competitive Electric segment:

• A 10% increase in retail electricity revenues was driven by higher pricing, partially offset by the effect of an 11% decline in retail sales volumes. Higher retail prices reflected increases in natural gas prices that resulted in the regulatory-approved price-to-beat rate increases implemented in May 2005, October 2005 and January 2006. The decline in retail sales volumes reflected a net loss of customers due to competitive activity and lower average consumption per residential and small business customer.

• A $162 million ($105 million after-tax) charge was recorded in the fourth quarter of 2006 for a special residential customer appreciation bonus. See discussion in Note 9 to Financial Statements for details.

• The decline in wholesale electricity revenues reflected the reporting of wholesale electricity trading activity on a net basis in 2006 as described in Note 1 to Financial Statements.

• Wholesale balancing net revenues/purchases are subject to high variability as the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes as measured in 15-minute intervals. See Note 1 to Financial Statements for a discussion regarding reporting of ERCOT balancing activities.

• The gains arising from risk management and trading activities in 2006 primarily reflect the unrealized effects of changes in natural gas prices and market heat rates on positions in the long-term hedging program implemented in the fourth quarter of 2005, while the losses in 2005 primarily represent realized losses on prior years’ hedging activities.

The 2% revenue increase in the Regulated Delivery segment reflected higher transmission and distribution tariffs as well as growth in points of delivery.

The decline in net intercompany sales elimination reflected lower sales by Regulated Delivery to REP subsidiaries of TCEH, while its sales to nonaffiliated REPs increased.

55

Gross Margin

	Predecessor
	Year Ended December 31,
	2006		% of Revenue		2005		% of Revenue
Operating revenues	$	10,856	100	%	$	10,662	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		2,784	26			4,261	40
Operating costs		1,373	13			1,425	13
Depreciation and amortization of generation and delivery assets		813	7			764	7
Gross margin	$	5,886	54	%	$	4,212	40	%

Gross margin increased $1.674 billion, or 40%, to $5.886 billion in 2006.

• The Competitive Electric segment’s gross margin increased $1.659 billion, or 55%, to $4.689 billion. The gross margin increase reflected the regulatory-approved price-to-beat increases and unrealized net gains from cash flow hedge ineffectiveness and mark-to-market valuations of hedged positions.

• The Regulated Delivery segment’s gross margin increased $15 million, or 1%, to $1.205 billion in 2006, driven by higher revenues.

Fuel, purchased power costs and delivery fees declined $1.477 billion, or 35%, to $2.784 billion primarily due to the realignment of wholesale energy operations and the resulting reporting of wholesale trading activity on a net basis in 2006 as discussed in Note 1 to the Financial Statements.

Operating costs decreased $52 million, or 4%, to $1.373 billion in 2006.

• The Competitive Electric segment’s operating costs decreased $64 million, or 10%, primarily reflecting lower maintenance costs due to both nuclear generation units having scheduled refueling outages in 2005 compared to one in 2006, as well as lower incentive compensation expense in 2006 and the absence of combustion turbine lease expense in 2006 resulting from the purchase of a lease trust interest in early 2006 (see Note 5 to Financial Statements).

• Regulated Delivery’s operating costs increased $12 million, or 2%, driven by fees paid to third-party transmission entities.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants and the delivery system shown in the gross margin table above) increased $54 million, or 7%, to $830 million in 2006. The increased expense reflects depreciation related to normal additions and replacements of property and higher expense associated with mining land reclamation activities.

56

SG&A expenses increased $38 million, or 5%, to $819 million in 2006. The increase reflected:

• $39 million in costs associated with the new generation development programs, principally salaries and consulting expenses;

• $17 million in higher fees related to the sale of accounts receivable program due to higher interest rates;

• $12 million in executive severance costs, and

• $12 million in higher bad debt expense primarily reflecting higher retail accounts receivable balances due to higher prices,

partially offset by:

• $20 million in lower stock-based incentive compensation expense due primarily to fewer share awards and lower expense related to a deferred compensation plan;

• $9 million in lower consulting fees related to various strategic initiatives, including fees in 2005 relating to the Luminant Operating System, and

• $7 million in lower compensation expense resulting from cost reduction initiatives.

Franchise and revenue-based taxes increased $26 million, or 7%, to $390 million reflecting higher state gross receipts taxes due to higher revenues and higher city franchise tax assessments under an Oncor cities rate settlement. See Note 11 to Financial Statements.

Other income totaled $121 million in 2006 and $151 million in 2005. Other deductions totaled $269 million in 2006, which included a $198 million impairment charge related to natural gas-fueled generation plants, and $45 million in 2005. See Note 15 to Financial Statements for details of other income and deductions.

Interest expense and related charges increased $28 million, or 3%, to $830 million in 2006. The increase reflected $69 million from higher average interest rates (including the effect of interest rate swap transactions), partially offset by $30 million in increased capitalized interest and $11 million due to lower average borrowings.

Income tax expense from continuing operations totaled $1.263 billion in 2006 compared to $632 million in 2005. The effective tax rate was 33.9% in 2006 compared to 26.3% in 2005. The 2006 amount included a charge of $44 million (1.2 percentage point effective tax rate impact) representing an adjustment to net deferred tax liabilities arising from the enactment of the Texas margin tax as described in Note 13 to the Financial Statements. The 2005 amount included $138 million in additional tax benefit (5.7 percentage point effective tax rate impact) related to the TXU Europe write-off as described in Note 4 to the Financial Statements and $29 million benefit (1.2 percentage point effective tax rate impact) related to the release of a tax reserve.

Income from continuing operations (an after-tax measure) increased $690 million, or 39%, to $2.465 billion in 2006.

• Earnings in the Competitive Electric segment increased $938 million, or 66%, to $2.367 billion driven primarily by improved gross margin partially offset by a charge for the write-down of the natural gas-fueled generation plants.

• Earnings in the Regulated Delivery segment decreased $7 million, or 2%, to $344 million driven by expenses in 2006 related to the cities rate settlement and the InfrastruX Energy Services joint venture.

• Corporate and Other net expenses totaled $246 million in 2006 and $5 million in 2005. The increase reflected (all amounts after-tax):

^¡ a $138 million tax benefit in 2005 related to TXU Europe (see Note 4 to Financial Statements);

^¡ an $85 million increase (to $241 million) in net interest expense related to advances from subsidiaries reflecting higher balances and interest rates;

^¡ a $17 million gain in 2006 related to a settlement of a telecommunications contract dispute, and

^¡ $10 million and $23 million of insurance recoveries in 2006 and 2005, respectively, related to the 2005 shareholders’ litigation settlement.

Income from discontinued operations (an after-tax measure) totaled $87 million in 2006 and $5 million in 2005. See Note 4 to Financial Statements for details.

57

Competitive Electric Segment

Financial Results

	Combined (a)			Successor			Predecessor
	Year Ended December 31, 2007			Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007
										Year Ended December 31,
										2006			2005
Operating revenues	$	6,509		$	179		$	6,330		$	9,549		$	9,552
Costs and expenses:
Fuel, purchased power costs and delivery fees		4,061			852			3,209			3,928			5,545
Operating costs		595			124			471			604			668
Depreciation and amortization		568			315			253			334			313
Selling, general and administrative expenses		643			154			489			571			522
Franchise and revenue-based taxes		111			30			81			126			114
Other income		(24	)		(2	)		(22	)		(23	)		(64	)
Other deductions		743			8			735			215			15
Interest income		(281	)		(10	)		(271	)		(203	)		(70	)
Interest expense and related charges		966			609			357			389			393
Total costs and expenses		7,382			2,080			5,302			5,941			7,436
Income (loss) from continuing operations before income taxes and cumulative effect of changes in accounting principles		(873	)		(1,901	)		1,028			3,608			2,116
Income tax (benefit) expense		(350	)		(656	)		306			1,241			687
Income (loss) from continuing operations before cumulative effect of changes in accounting principles	$	(523	)	$	(1,245	)	$	722		$	2,367		$	1,429

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP presentation.

58

Competitive Electric Segment

Sales Volume Data

	Year Ended December 31,						Change %		Change %
	2007 (a)		2006		2005		2007/2006		2006/2005
	Combined		Predecessor
Sales volumes:
Retail electricity sales volumes – gigawatt hours (GWh):
Historical service territory:
Residential	23,029		25,932		29,239		(11.2	)	(11.3	)
Small business (b)	6,670		7,753		9,004		(14.0	)	(13.9	)
Total historical service territory	29,699		33,685		38,243		(11.8	)	(11.9	)
Other territories:
Residential	4,194		3,663		3,416		14.5		7.2
Small business (b)	813		671		674		21.2		(0.4	)
Total other territories	5,007		4,334		4,090		15.5		6.0
Large business and other customers	14,537		14,031		15,843		3.6		(11.4	)
Total retail electricity	49,243		52,050		58,176		(5.4	)	(10.5	)
Wholesale electricity sales volumes	39,112		36,931		52,001		5.9		(29.0	)
Net sales (purchases) of balancing electricity to/from ERCOT(c)	669		874		4,787		(23.5	)	(81.7	)
Total sales volumes	89,024		89,855		114,964		(0.9	)	(21.8	)
Average volume (kWh) per retail customer (d):
Residential	14,532		15,359		15,825		(5.4	)	(2.9	)
Small business	28,640		30,360		32,078		(5.7	)	(5.4	)
Large business and other customers	375,949		285,277		243,538		31.8		17.1
Weather (service territory average) – percent of normal (e):
Percent of normal:
Cooling degree days	99.1	%	117.6	%	107.0	%
Heating degree days	99.6	%	79.2	%	90.0	%

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP presentation.

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

(c) See Note 1 to Financial Statements for discussion of trading and ERCOT balancing activity.

(d) Calculated using average number of customers for period.

(e) 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).

59

Competitive Electric Segment

Customer Count Data

	Year Ended December 31,			Change %		Change %
	2007	2006	2005	2007/2006		2006/2005
	Successor	Predecessor
Customer counts:
Retail electricity customers (end of period and in thousands) (a):
Historical service territory:
Residential	1,543	1,624	1,769	(5.0	)	(8.2	)
Small business (b)	241	258	281	(6.6	)	(8.2	)
Total historical service territory	1,784	1,882	2,050	(5.2	)	(8.2	)
Other territories:
Residential	332	247	213	34.4		16.0
Small business (b)	15	9	7	66.7		28.6
Total other territories	347	256	220	35.5		16.4
All territories:
Residential	1,875	1,871	1,982	0.2		(5.6	)
Small business (b)	256	267	288	(4.1	)	(7.3	)
Total all territories	2,131	2,138	2,270	(0.3	)	(5.8	)
Large business and other customers	33	44	55	(25.0	)	(20.0	)
Total retail electricity customers	2,164	2,182	2,325	(0.8	)	(6.2	)

(a) Based on number of meters.

(b) Customers with demand of less than 1 MW.

60

Competitive Electric Segment

Revenue and Market Share Data

	Combined (a)			Successor			Predecessor
	Year Ended December 31, 2007			Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31,
										2006			2005
Operating revenues:
Retail electricity revenues:
Historical service territory:
Residential	$	3,129		$	538		$	2,591		$	3,804		$	3,444
Small business (b)		980			180			800			1,153			1,086
Total historical service territory		4,109			718			3,391			4,957			4,530
Other territories:
Residential		589			116			473			559			405
Small business (b)		102			22			80			80			65
Total other territories		691			138			553			639			470
Large business and other customers		1,356			286			1,070			1,357			1,330
Total retail electricity revenues		6,156			1,142			5,014			6,953			6,330
Wholesale electricity revenues (c)		2,142			505			1,637			2,278			2,807
Net sales (purchases) of balancing electricity to/from ERCOT (c)		(23	)		(9	)		(14	)		(31	)		225
Income (loss) from risk management and trading activities		(2,046	)		(1,492	)		(554	)		153			(164	)
Amortization of intangibles (d)		(50	)		(50	)		—			—			—
Other operating revenues (e)		330			83			247			196			354
Total operating revenues	$	6,509		$	179		$	6,330		$	9,549		$	9,552
Risk management and trading activities:
Unrealized net gains (losses), including cash flow hedge ineffectiveness, related to unsettled positions	$	(2,165	)	$	(1,476	)	$	(689	)	$	240		$	(6	)
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the current period		(113	)		(80	)		(33	)		32			(12	)
Realized net gains (losses) on settled positions (f)		232			64			168			(119	)		(146	)
Total income (loss)	$	(2,046	)	$	(1,492	)	$	(554	)	$	153		$	(164	)

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP presentation.

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

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

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

(e) Includes a $162 million charge for a special customer appreciation bonus in 2006. This charge does not affect the computation of residential average revenues per MWh. See Note 9 to Financial Statements.

(f) Includes physical commodity trading activity not subject to mark-to-market accounting of $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, $34 million in net losses for 2006 and $61 million in net gains for 2005.

61

Competitive Electric Segment

Revenue and Market Share Data (cont.)

	Year Ended December 31,									Change %		Change %
	2007			2006			2005			2007/2006		2006/2005
	Combined (a)			Predecessor
Average revenues per MWh:
Residential	$	136.55		$	147.43		$	117.86		(7.4	)	25.1
Estimated share of ERCOT retail markets (b)(c)(d):
Historical service territory:
Residential		62	%		66	%		73	%
Small business		59	%		64	%		71	%
Total ERCOT:
Residential		36	%		37	%		40	%
Small business		25	%		26	%		29	%
Large business and other customers		10	%		14	%		20	%

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP presentation.

(b) Based on number of meters.

(c) Estimated market share is based on the number of customers that have choice.

(d) Calculations based on TXU Energy customer segmentation and ERCOT total customer counts.

62

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Combined (a)		Successor		Predecessor
	Year Ended December 31, 2007		Period from October 11, 2007 through December 31, 2007		Period From January 1, 2007 through October 10, 2007		Year Ended December 31,
							2006		2005
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	87	$	21	$	66	$	85	$	78
Lignite/coal		594		127		467		475		475
Total baseload fuel		681		148		533		560		553
Natural gas fuel and purchased power		1,737		302		1,435		1,787		3,285
Amortization of intangibles (b)		67		67		—		—		—
Other costs		281		68		213		228		281
Fuel and purchased power costs (c)		2,766		585		2,181		2,575		4,119
Delivery fees (d)		1,295		267		1,028		1,353		1,426
Total	$	4,061	$	852	$	3,209	$	3,928	$	5,545

	Combined (a)			Predecessor
	Year Ended December 31,									Change % 2007/2006		Change % 2006/2005
	2007			2006			2005
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	4.61		$	4.29		$	4.23		7.5		1.4
Lignite/coal (e)	$	14.09		$	11.73		$	11.68		20.1		0.4
Natural gas fuel and purchased power	$	61.81		$	62.99		$	60.37		(1.9	)	4.3
Delivery fees per MWh	$	25.84		$	25.71		$	24.20		0.5		6.2
Production and purchased power volumes (GWh):
Nuclear		18,821			19,795			18,371		(4.9	)	7.8
Lignite/coal		46,494			45,579			45,933		2.0		(0.8	)
Total baseload generation		65,315			65,374			64,304		—		1.7
Natural gas-fueled generation		3,991			3,989			3,504		—		13.8
Purchased power (c)		24,102			24,380			50,920		(1.1	)	(52.1	)
Total energy supply		93,408			93,743			118,728		(0.4	)	(21.0	)
Less line loss and power imbalances		4,384			3,888			3,764		12.8		3.3
Net energy supply volumes		89,024			89,855			114,964		(0.9	)	(21.8	)
Baseload capacity factors (%):
Nuclear		93.5	%		98.8	%		91.5	%	(5.4	)	8.0
Lignite/coal		90.9	%		89.1	%		89.8	%	2.0		(0.8	)
Total baseload		91.6	%		91.8	%		90.3	%	(0.2	)	1.7

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP presentation.

(b) Represents 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.

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

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

(e) 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.

63

Competitive Electric Segment — Financial Results — 2007 compared to 2006

Operating revenues decreased $3.040 billion, or 32%, to $6.509 billion in 2007, as shown in the following table:

	Combined (a)			Successor			Predecessor
	Year Ended December 31, 2007			Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31, 2006
Total retail electricity revenues	$	6,156			1,142			5,014		$	6,953
Wholesale electricity revenues		2,142			505			1,637			2,278
Wholesale balancing activities		(23	)		(9	)		(14	)		(31	)
Income (loss) from risk management and trading activities		(2,046	)		(1,492	)		(554	)		153
Amortization of intangibles (b)		(50	)		(50	)		—			—
Other operating revenues		330			83			247			196
Total operating revenues	$	6,509		$	179		$	6,330		$	9,549

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP presentation.

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

The $797 million, or 11%, decrease in retail electricity revenues reflected the following:

• Lower average pricing (including customer mix effects) contributed $422 million to the revenue decrease. Lower average retail pricing 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 price-to-beat 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 5% decline in retail sales volumes contributed $375 million to the revenue decrease. Residential and small business volumes declined 9% reflecting lower average consumption per customer of 6% due in part to unusually cool summer weather in 2007 and hotter than normal weather in 2006; additionally, competitive activity resulted in net volume declines in EFH Corp.’s historical service territory that were partially offset by net increases in other territories. Large business market volumes increased 4% reflecting a change in customer mix.

• Total retail electricity customer counts at December 31, 2007 declined 1% from December 31, 2006. A 5% decline in total residential and small business customer counts in EFH Corp.’s historical service territory was largely offset by growth in other territories.

Wholesale electricity revenues decreased $136 million, or 6%. Lower prices contributed $271 million to the decrease as average wholesale prices declined 11% reflecting lower natural gas prices during 2007. The pricing impact was partially offset by a $135 million contribution from volume growth of 6% due in part to the decline in retail sales volumes.

Wholesale balancing activity comparisons are not meaningful because the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, that are highly variable.

64

Results from risk management and trading activities include realized and unrealized gains and losses associated with financial instruments used for hedging and trading purposes, as well as gains and losses on physical sales and purchases of commodities for trading purposes. Because most of the hedging and risk management activities are intended to mitigate the risk of commodity price movements on revenues and fuel and purchased power costs, these results should not be viewed in isolation, but rather taken together with the effects of pricing and cost changes on gross margin. Following is an analysis of activities for the years ended December 31, 2007 and 2006:

Year Ended December 31, 2007— Unrealized mark-to-market net losses totaling $2.278 billion ($1.556 billion recorded in the Successor period) include:

• $2.098 billion in net losses related to hedge positions, which includes $2.043 billion in net losses related to unsettled positions and $55 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 $114 million of net gains related to unsettled positions and $24 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;

• $60 million in net losses related to trading positions, which includes $13 million in net losses on unsettled positions and $47 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;

• $239 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 $232 million ($64 million recorded in the Successor period) include:

• $198 million in net gains related to hedge positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the period, and

• $34 million in net gains related to trading positions.

Year Ended December 31, 2006— Unrealized mark-to-market net gains totaling $272 million include:

• $239 million in hedge ineffectiveness net gains, which includes $218 million in net gains related to unsettled positions and $21 million in net gains that represent reversals of previously recorded unrealized net losses related to positions settled in the period. These amounts relate to positions accounted for as cash flow hedges;

• $135 million in net gains related to unsettled hedge positions, and

• a $109 million “day one” loss on a related series of commodity price hedges entered into at below-market prices.

Realized net losses totaling $119 million include:

• $65 million in net losses related to hedge positions that offset hedged electricity revenues recognized in the period, and

• $54 million in net losses related to trading positions.

65

Gross Margin

	Combined (a)				Successor			Predecessor
	Year Ended December 31, 2007		% of Revenue		Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007		Year Ended December 31, 2006		% of Revenue
Operating revenues	$	6,509	100	%	$	179		$	6,330	$	9,549	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		4,061	62			852			3,209		3,928	41
Generation plant operating costs		595	9			124			471		604	6
Depreciation and amortization of generation assets		482	8			234			248		328	4
Gross margin	$	1,371	21	%	$	(1,031	)	$	2,402	$	4,689	49	%

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP measure.

Gross margin decreased $3.318 billion, or 71%, to $1.371 billion in 2007 driven by the decrease in operating revenues.

Gross margin as a percent of revenues decreased 28 percentage points to 21%. The decrease reflected:

• the effect of results from risk management and trading activities (17 percentage point margin decrease);

• the effect of lower average retail electricity pricing (four percentage point margin decrease);

• the effect of incremental depreciation and amortization expense on the Successor resulting from stepped-up property, plant and equipment values and amortization of the intangible values recorded in connection with purchase accounting of customers, large business contracts, power sales agreements, emission credits and fuel and power purchase contracts (see Notes 2 and 3 to Financial Statements for more information), (four percentage point margin decrease);

• the effect of a decrease in residential and small business retail sales volumes and an increase in wholesale sales volumes (two percentage point margin decrease);

• the effect of higher lignite mining costs (one percentage point margin decrease), and

• the effect of lower nuclear generation volumes (one percentage point margin decrease).

Fuel, purchased power costs and delivery fees increased $133 million, or 3%, to $4.061 billion. The increase includes $67 million of net expense recorded in the 2007 Successor 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. The increase also reflected purchases of power due to a scheduled refueling and major maintenance outage for one of the two Comanche Peak nuclear units. Maintenance work during the 55-day outage, which ended in April 2007 and drove a five percent decline in nuclear generation volumes for the year, included the replacement of the unit’s steam generators and reactor vessel head. Higher fuel costs also reflected increased mining expenses driven by significantly above normal summer rainfall.

Operating costs decreased $9 million to $595 million in 2007. The decrease reflected reductions in costs largely resulting from generation technical support outsourcing service agreements, partially offset by $8 million for the utilization of SO₂ emission credits in 2007 for the lignite/coal-fueled generation units and $7 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. During the period from October 11, 2007 to December 31, 2007, expense related to the amortization of the intangible value of SO₂ emission credits recorded in connection with purchase accounting are reflected in fuel costs.

66

Depreciation and amortization (consisting of amounts related to generation plants shown in the gross margin table above and amounts related to the retail customer relationship intangible asset resulting from purchase accounting) increased $234 million to $568 million. The increase includes $157 million of incremental depreciation expense in the Successor period resulting from stepped-up property, plant and equipment values and $79 million in incremental amortization expense in the Successor period related to the intangible value of retail customer relationships recorded in connection with purchase accounting. 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 natural gas-fueled generation plants in the second quarter of 2006 and lower expense associated with mining reclamation obligations.

SG&A expenses increased $72 million, or 13%, to $643 million in 2007. The increase reflected:

• $35 million in increased retail marketing expenses;

• $16 million in higher professional fees primarily for retail billing and customer care systems enhancements and marketing/strategic projects;

• $14 million in higher third-party service provider fees, primarily in the retail business, including effects of additional services and projects;

• $11 million in higher salary and benefit costs primarily driven by an increase in staffing in retail operations;

• $9 million in other individually insignificant costs, and

• $3 million in higher incentive compensation,

partially offset by:

• $10 million in lower bad debt expense driven by a decrease in delinquencies and lower accounts receivable balances, and

• $6 million in severance costs in 2006.

Other income totaled $24 million in 2007 and $23 million in 2006. Other income in 2007 includes $7 million in insurance recoveries, $6 million of mineral royalty income, $6 million in penalties received due to nonperformance under a coal transportation agreement and $5 million in gains on the sale of undeveloped land. Other income in 2006 includes $11 million in gains on the sale of undeveloped land, $6 million of mineral royalty income and a $2 million insurance recovery related to a generation plant outage in 2001.

Other deductions totaled $743 million in 2007 ($61 million recorded in the Successor period) and $215 million in 2006. The 2007 amount includes:

• net charges of $757 million related to the canceled development of eight coal-fueled generation units (see Note 7 to 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. (Predecessor) has ceased operating for its own benefit (see Note 5 to 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 8 to Financial Statements);

• $10 million in equity losses (representing amortization expense) related to the ownership interest in the EFH Corp. subsidiary holding the capitalized software licensed to Capgemini;

• $6 million of litigation-related charges, and

• a $5 million charge for the termination of an equipment purchase agreement.

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).

67

Interest income increased $78 million to $281 million in 2007 reflecting $58 million due to higher average rates on advances to affiliates and $20 million due to higher average advance balances.

Interest expense and related charges increased by $577 million to $966 million in 2007. The increase reflected $525 million in higher average borrowings, driven by the Merger-related financings, and $144 million due to higher average interest rates, partially offset by $92 million in increased capitalized interest.

Income tax benefit totaled $350 million in 2007 compared to an expense of $1.241 billion in 2006. The effective income tax rate was 40.1% on a loss in 2007 and 34.4% on income in 2006. The increased rate reflects the deferred tax impacts of the enactment of the Texas margin tax as described in Note 13 and the effect of ongoing relatively fixed tax benefits such as lignite depletion, partially offset by higher Texas state taxes and higher interest accrued related to uncertain tax positions.

Results from continuing operations decreased $2.890 billion to a loss of $523 million in 2007 driven by unrealized mark-to-market losses on positions in the long-term hedging program, the charges related to the cancellation of the development of eight lignite/coal-fueled generation units, higher net interest expense, lower retail sales prices and the effects of purchase accounting.

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Competitive Electric Segment Financial Results — 2006 compared to 2005

Operating revenues decreased $3 million to $9.549 billion in 2006, as shown in the following table.

	Predecessor
	Year Ended December 31,
	2006			2005			Increase (Decrease)
Total retail electricity revenues	$	6,953		$	6,330		$	623
Accrued customer appreciation bonus		(162	)		—			(162	)
Wholesale electricity revenues		2,278			2,807			(529	)
Wholesale balancing activities		(31	)		225			(256	)
Income (loss) from risk management and trading activities		153			(164	)		317
Other operating revenues		358			354			4
Total operating revenues	$	9,549		$	9,552		$	(3	)

The 10% increase in retail electricity revenues reflected the following:

• Higher average pricing contributed $1.290 billion to the revenue increase. Higher retail prices reflected increases in natural gas prices that resulted in the regulatory-approved price-to-beat rate increases implemented in May 2005, October 2005 and January 2006.

• The effect of higher retail pricing was partially offset by $667 million in lower retail volumes. Total retail sales volumes declined 11%. Residential and small business volumes fell 10% on a net loss of customers due to competitive activity and lower average consumption per customer. The lower consumption reflected customer efficiency measures in response to prices and warmer weather. Large business market sales volumes declined 11% as the effect of fewer customers was partially offset by higher average consumption per customer. A change in large business customer mix reflected a continuing strategy to improve margins.

• Retail electricity customer counts at December 31, 2006 declined 6% from December 31, 2005. Total residential and small business customer counts in EFH Corp.’s historical service territory declined 8% and in all combined territories declined 6%.

A $162 million ($105 million after-tax) charge was recorded in the fourth quarter of 2006 for a special residential customer appreciation bonus. See discussion in Note 9 to Financial Statements.

The decline in wholesale electricity revenues reflected the reporting of wholesale electricity trading activity on a net basis in 2006 as described in Note 1 to Financial Statements. This effect was partially offset by higher wholesale sales prices.

Wholesale balancing net revenues/purchases are subject to high variability as the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes as measured in 15-minute intervals. See Note 1 for a discussion regarding the change in reporting of ERCOT balancing activities.

69

Following is an analysis of risk management and trading activities for the years ended December 31, 2006 and 2005:

Year Ended December 31, 2006 —Unrealized mark-to-market net gains totaling $272 million include:

• $239 million in hedge ineffectiveness net gains, which includes $218 million in net gains related to unsettled positions and $21 million in net gains that represent reversals of previously recorded unrealized net losses related to positions settled in the period;

• $135 million in net gains related to unsettled hedge positions, and

• a $109 million “day one” loss on a related series of commodity price hedges entered into at below-market prices.

Realized net losses totaling $119 million include:

• $65 million in net losses related to hedge positions that offset hedged electricity revenues recognized in the period, and

• $54 million in net losses related to trading positions.

Year Ended December 31, 2005 —Unrealized mark-to-market net losses totaling $18 million include:

• $27 million in hedge ineffectiveness net losses, which includes $38 million in net losses related to unsettled positions and $11 million in net gains that represent reversals of previously recorded net losses related to positions settled in the period, and

• $8 million in net gains related to trading positions.

Realized net losses totaling $146 million include:

• $259 million in net losses related to hedge positions that offset hedged electricity revenues recognized in the period, and

• $113 million in net gains related to trading positions.

Gross Margin

	Predecessor
	Year Ended December 31,
	2006		% of Revenue		2005		% of Revenue
Operating revenues	$	9,549	100	%	$	9,552	100	%
Costs and expenses:
Fuel, purchased power costs and delivery fees		3,928	41			5,545	58
Generation plant operating costs		604	6			668	7
Depreciation and amortization of generation assets		328	4			309	3
Gross margin	$	4,689	49	%	$	3,030	32	%

Gross margin increased $1.659 billion, or 55%, to $4.689 billion in 2006. This growth primarily reflected the relatively low fuel costs of TCEH’s nuclear and lignite/coal-fueled baseload plants, as well as the continued improved productivity of the baseload plants, in an environment of increasing wholesale power prices. The increased wholesale power prices were driven by rising natural gas prices. Retail prices, including price-to-beat rates, were increased in response to higher wholesale prices. In addition to higher retail prices, the gross margin increase reflected $265 million in unrealized net gains from cash flow hedge ineffectiveness and mark-to-market valuations of hedged positions. An 8% increase in production volumes at the nuclear generation plant also contributed to higher gross margin as this generation represents the lowest marginal cost of electricity to supply retail and wholesale customers. The gross margin performance was tempered by the effects of lower retail sales volumes and the effect of the customer appreciation bonus accrual.

70

Gross margin as a percent of revenues increased 17 percentage points to 49%. The improvement reflected the following estimated effects:

• higher pricing, as the average retail sales price per MWh rose 23% and the average wholesale sales price per MWh rose 17% (10 percentage point margin increase);

• the effect of reporting wholesale electricity trading activity on a net basis (6 percentage point margin increase);

• the effect of unrealized cash flow hedge ineffectiveness and mark-to-market net gains related to hedged positions (1 percentage point margin increase), and

• the combined effect of increased nuclear generation production volumes and less need for purchased electricity volumes (2 percentage point margin increase),

partially offset by:

• lower retail sales volumes (2 percentage point margin decrease), and

• the customer appreciation bonus accrual (1 percentage point margin decrease).

Fuel, purchased power costs and delivery fees declined $1.617 billion, or 29%, to $3.928 billion, reflecting the reporting of wholesale trading activity on a net basis in 2006 as discussed in Note 1 to the Financial Statements and the favorable impact of higher nuclear generation volumes to meet sales demand, partially offset by the effect of higher average prices of purchased electricity.

Operating costs decreased $64 million, or 10%, to $604 million in 2006. The decrease reflected:

• $49 million in lower maintenance costs due to both nuclear generation units having scheduled refueling outages in 2005 compared to one in 2006, and reduced other maintenance activity;

• $9 million in lower incentive compensation expense, and

• the absence of $10 million in combustion turbine lease expense in 2006 resulting from the purchase of a lease trust interest in early 2006 (see Note 5 to Financial Statements),

partially offset by $8 million in net severance and early retirement costs associated with generation outsourcing services agreements entered into in early 2006.

Depreciation and amortization (consisting almost entirely of amounts related to generation plants shown in the gross margin table above) increased $21 million, or 7%, to $334 million reflecting higher costs associated with mining land reclamation activities and increased amortization of intangible software assets, partially offset by $7 million in lower depreciation due to the impairment of natural gas-fueled generation plants in the second quarter of 2006.

SG&A expenses increased by $49 million, or 9%, to $571 million in 2006. The increase reflected:

• $39 million in costs associated with the new generation development programs, principally salaries and consulting expenses;

• $14 million in higher bad debt expense reflecting higher retail accounts receivable balances due to higher prices and the effect of a temporary regulatory-mandated deferred payment arrangement and disconnect moratorium applicable to certain retail customers;

• $14 million in higher fees related to the sale of accounts receivable program due to higher interest rates, and

• $6 million in executive severance expense (including amounts allocated from the Predecessor),

partially offset by:

• $8 million in lower consulting fees primarily reflecting expenses in 2005 for the development and implementation of the Luminant Operating System to improve productivity;

• $7 million in lower stock-based incentive compensation and deferred compensation expenses, and

• $7 million in lower salaries resulting from cost reduction initiatives in late 2005.

Franchise and revenue-based taxes increased $12 million, or 11%, to $126 million reflecting higher state gross receipts taxes due to higher revenues.

71

Other income totaled $23 million in 2006 and $64 million in 2005. The 2006 amount includes $11 million in gains on the sale of undeveloped land, $6 million in mineral royalty income and a $2 million insurance recovery related to a generation plant outage in 2001.

The 2005 amount included:

• $33 million in gains on the sale of undeveloped land and mining land;

• an $8 million insurance recovery related to a generation plant fire in 2002;

• a $7 million gain on the sale of an investment in an out-of-state electricity transmission project;

• a $4 million gain in connection with a customer’s termination of an electricity services contract, and

• a $2 million gain on the sale of surplus equipment.

Other deductions totaled $215 million in 2006 and $15 million in 2005. The 2006 amount includes:

• a $198 million charge related to the write-down of the natural gas-fueled generation plants to fair value (see Note 8 to Financial Statements);

• $10 million in equity losses (representing amortization expense) related to the ownership interest in the EFH Corp. subsidiary holding the capitalized software licensed to Capgemini;

• $6 million of litigation-related charges, and

• a $5 million charge for the termination of an equipment purchase agreement,

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

The 2005 amount includes:

• a $12 million charge related to a counterparty default under a coal contract;

• $12 million in transition costs associated with the Capgemini outsourcing agreement;

• $7 million in equity losses (representing amortization expense) related to the ownership interest in the EFH Corp. subsidiary holding the capitalized software licensed to Capgemini;

• $6 million in accretion expense related to a lease liability for combustion turbines no longer operated for TCEH’s benefit;

• a $16 million net credit from a reduction in the combustion turbine lease liability due to a change in estimated sublease proceeds as the original charge associated with this liability was reported in this line item, the related credit was similarly reported, and

• the release of a previously recorded $6 million reserve for restoration of a site that is being used in generation plant development.

Interest income increased by $133 million to $203 million in 2006 reflecting $91 million due to higher average advances to affiliates and $42 million due to higher average rates.

Interest expense and related charges decreased by $4 million, or 1%, to $389 million in 2006. The decrease reflects $29 million of higher capitalized interest, partially offset by higher average interest rates of $25 million.

Income tax expense on income from continuing operations totaled $1.241 billion in 2006 compared to $687 million in 2005. The effective tax rate was 34.4% in 2006 compared to 32.5% in 2005. The 2006 amount included a charge of $44 million (a 1.2 percentage point effective tax rate impact) representing an adjustment to deferred tax liabilities arising from the enactment of the Texas margin tax as described in Note 13 to the Financial Statements. The 2005 amount reflected a benefit of $29 million representing a tax reserve adjustment (1.4 percentage point effective tax rate impact) and a charge of $10 million (a 0.5 percentage point effective tax rate impact) related to the settlement of the IRS audit for the 1994 to 1996 years.

Income from continuing operations increased $938 million, or 66%, to $2.367 billion in 2006 driven by improved gross margin and higher interest income, partially offset by the charge for the write-down of the natural gas-fueled generation plants and expenses related to the new generation development program.

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Regulated Delivery Segment

Financial Results

	Combined (a)			Successor				Predecessor
	Year Ended December 31, 2007			Period from October 11, 2007 through December 31, 2007				Period From January 1, 2007 through October 10, 2007
											Year Ended December 31,
											2006			2005
Operating revenues	$	2,519		$	532			$	1,987		$	2,449		$	2,394
Costs and expenses:
Operating costs		819			182				637			770			758
Depreciation and amortization		462			96				366			476			446
Selling, general and administrative expenses		184			45				139			177			201
Franchise and revenue-based taxes		260			62				198			262			247
Other income		(14	)		(11	)			(3	)		(2	)		(4	)
Other deductions		34			7				27			24			11
Interest income		(56	)		(12	)	��		(44	)		(58	)		(59	)
Interest expense and related charges		312			70				242			286			269
Total costs and expenses		2,001			439				1,562			1,935			1,869
Income before income taxes		518			93				425			514			525
Income tax expense		190			30				160			170			174
Net income	$	328		$	63			$	265		$	344		$	351

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP measure.

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Regulated Delivery Segment

Operating Data

	Year Ended December 31,
	2007	2006	2005	% Change 2007/2006		% Change 2006/2005
	Combined	Predecessor
Operating statistics – volumes:
Electric energy delivered (GWh)	106,146	107,098	106,780	(0.9	)	0.3
Reliability statistics (a):
System Average Interruption Duration Index (SAIDI) (nonstorm)	77.88	79.09	76.79	(1.5	)	3.0
System Average Interruption Frequency Index (SAIFI) (nonstorm)	1.10	1.17	1.17	(6.0	)	—
Customer Average Interruption Duration Index (CAIDI) (nonstorm)	70.64	67.54	65.60	4.6		3.0
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters)	3,093	3,056	3,013	1.2		1.4

	Combined (b)		Successor		Predecessor
	Year Ended December 31, 2007		Period from October 11, 2007 through December 31, 2007		Period From January 1, 2007 through October 10, 2007		Year Ended December 31,
							2006		2005
Operating Revenues:
Electricity distribution revenues (c):
Affiliated (TCEH)	$	1,029	$	208	$	821	$	1,137	$	1,276
Nonaffiliated		1,178		257		921		1,046		879
Total distribution revenues		2,207		465		1,742		2,183		2,155
Third-party transmission revenues		259		60		199		236		213
Other miscellaneous revenues		53		8		45		30		26
Total operating revenues	$	2,519	$	533	$	1,986	$	2,449	$	2,394

(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) See “Presentation and Analysis of Results” above for explanation of this non-GAAP measure.

(c) Includes transition charge revenue associated with the issuance of securitization bonds totaling $29 million for the period October 11, 2007 through December 31, 2007, $116 million for the period January 1, 2007 through October 10, 2007 and $151 million and $152 million for the years ended December 31, 2006 and 2005, respectively. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs.

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Regulated Delivery’s results are being impacted by the effects of the 2006 cities rate settlement. Based on the final agreements, including the participation of the nonlitigant cities, payments to the cities are estimated to total approximately $70 million, including incremental franchise taxes. This amount is being recognized in net income almost entirely over the period from May 2006 through June 2008. Amounts recognized totaled $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.

Regulated Delivery Segment Financial Results — 2007 compared to 2006

Operating revenues increased $70 million, or 3%, to $2.519 billion in 2007. The revenue increase reflected:

• an estimated $27 million impact of growth in points of delivery;

• $26 million from increased distribution tariffs to recover higher transmission costs;

• $23 million in higher transmission revenues primarily due to rate increases approved in 2006 and 2007 to recover ongoing investment in the transmission system, and

• $19 million for installation of equipment for a third party that will facilitate Oncor’s technology initiatives,

partially offset by,

• an estimated $25 million effect of lower average consumption due in part to cooler, below normal summer weather in 2007 and hotter than normal weather in 2006, and

• $6 million in lower charges to REPs related to securitization bonds (offset by lower amortization of the related regulatory asset).

Gross Margin

	Combined (a)				Successor		Predecessor
	Year Ended December 31, 2007		% of Revenue		Period from October 11, 2007 through December 31, 2007		Period From January 1, 2007 through October 10, 2007		Year Ended December 31, 2006		% of Revenue
Operating revenues	$	2,519	100	%	$	532	$	1,987	$	2,449	100	%
Costs and expenses:
Operating costs		819	33			182		637		770	31
Depreciation of transmission and distribution assets		461	18			96		365		474	20
Gross margin	$	1,239	49	%	$	254	$	985	$	1,205	49	%

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP measure.

Operating costs increased $49 million, or 6%, to $819 million in 2007. The increase reflected $26 million in higher fees paid to other transmission entities, $18 million for costs of installation of equipment for a third party that will facilitate Oncor’s technology initiatives, $8 million in higher labor-related costs due to timing of equipment installation activities and $6 million in increased labor cost primarily for restoration of service as a result of weather events, partially offset by lower vegetation management expenses of $4 million.

Depreciation and amortization decreased $14 million, or 3%, to $462 million in 2007. The decrease reflected $18 million in lower depreciation due to a one-time adjustment related to retired property and $5 million in lower amortization of the regulatory assets associated with the securitization bonds (offset in revenues), partially offset by increases in depreciation due to ongoing investments in property, plant and equipment.

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SG&A expenses increased $7 million, or 4%, to $184 million in 2007. The increase reflected $5 million in higher outsourced service provider costs, $5 million for expenses related to the rebranding from TXU Electric Delivery Company to Oncor Electric Delivery Company, $3 million in increased incentive pay and benefit expense and $2 million in professional fees, partially offset by the effect of an $11 million decrease in shared services costs allocated by EFH Corp., which includes the effect of $3 million in severance expenses in 2006.

Franchise and revenue-based taxes decreased $2 million, or less than 1%, to $260 million in 2007. The decrease reflected a $4 million decrease in franchise fees due to lower delivered volumes, partially offset by $2 million in higher franchise fees under the 2006 cities rate settlement. 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, $5 million for the period January 1, 2007 through October 10, 2007 and $5 million for the year ended December 31, 2006.

Other income totaled $14 million in 2007 and $2 million in 2006. The increase is primarily due to $10 million in accretion in the Successor period of an adjustment (discount) to regulatory assets resulting from purchase accounting. See “Regulatory Assets and Liabilities” in Note 28 to Financial Statements for additional information.

Other deductions totaled $34 million in 2007 and $24 million in 2006. The 2007 amount includes:

• $26 million in costs as a result of the 2006 cities rate settlement (see Note 11 to Financial Statements);

• $3 million in costs related to the InfrastruX Energy Services joint venture, which was abandoned following the Merger, and

• $3 million in equity losses (representing amortization expense) related to the ownership interest in the EFH Corp. subsidiary holding the capitalized software licensed to Capgemini.

The 2006 amount includes:

• $13 million in costs under the 2006 cities rate settlement;

• $7 million in costs related to the InfrastruX Energy Services joint venture, and

• $4 million in equity losses (representing amortization expense) related to the ownership interest in the EFH Corp. subsidiary holding the capitalized software licensed to Capgemini.

Interest expense increased $26 million, or 9%, to $312 million in 2007. The increase reflects $20 million due to higher average borrowings, reflecting the ongoing capital investment in the business, and $6 million due to higher average interest rates.

Income tax expense totaled $190 million in 2007 compared to $170 million in 2006. The effective income tax rate increased to 36.7% in 2007 from 33.1% in 2006. The increased rate is primarily driven by higher Texas state income taxes, 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 $16 million, or 5%, to $328 million. This decrease was driven by higher costs associated with the 2006 cities rate settlement, increased interest expense due primarily to higher average borrowings and increased operating costs, partially offset by higher transmission revenues.

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Regulated Delivery Segment Financial Results — 2006 compared to 2005

Operating revenues increased $55 million, or 2%, to $2.449 billion in 2006. Delivered volumes rose less than 1%. The revenue increase reflected:

• $24 million in higher transmission revenues primarily due to rate increases approved in 2005 and 2006 to recover ongoing investment in the transmission system;

• an estimated $16 million due to growth in points of delivery, and

• $9 million from increased distribution tariffs to recover higher transmission costs.

The effect of warmer weather on electricity consumption was largely offset by end-user efficiency measures in response to higher prices and warmer weather.

Gross Margin

	Year Ended December 31,
	2006		% of Revenue		2005		% of Revenue
Operating revenues	$	2,449	100	%	$	2,394	100	%
Costs and expenses:
Operating costs		770	31	%		758	32	%
Depreciation of transmission and distribution assets		474	20	%		446	18	%
Gross margin	$	1,205	49	%	$	1,190	50	%

Operating costs rose $12 million, or 2%, to $770 million in 2006. The increase reflected $19 million in increased fees paid to third party transmission entities, partially offset by $6 million due to increased labor capitalization rates and timing of expenses related to advanced meter installations.

Depreciation and amortization (essentially all of which related to the delivery system as shown in the gross margin table above) increased $30 million, or 7%, to $476 million in 2006. The increase reflected $23 million in depreciation related to normal additions and replacements of property, plant and equipment and a $4 million adjustment related to capitalized software costs.

SG&A expenses decreased $24 million, or 12%, to $177 million in 2006. The decrease reflected:

• $8 million in lower incentive compensation expense;

• $4 million in decreased employee benefits expense;

• $3 million in lower bad debt expense;

• $3 million in lower legal and consulting fees, and

• $3 million in lower research and development costs,

partially offset by $3 million in higher sale of receivables program fees driven by higher interest rates.

Franchise and revenue-based taxes increased $15 million, or 6%, to $262 million in 2006. The increase was driven by higher delivered volumes in the period to which the tax applies and also includes $5 million in higher franchise fees under the 2006 cities rate settlement. See Note 11 to Financial Statements.

Other deductions totaled $24 million in 2006 and $11 million in 2005. The 2006 amount includes:

• $13 million in costs as a result of the cities rate settlement (See Note 11 to Financial Statements);

• $7 million in transition costs related to the InfrastruX Energy Services joint venture, and

• $4 million in equity losses (representing amortization expense) related to the ownership interest in the EFH Corp. subsidiary holding the capitalized software licensed to Capgemini.

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The 2005 amount included:

• $3 million in costs associated with transitioning the outsourced activities to Capgemini;

• $3 million in equity losses (representing amortization expense) related to the ownership interest in the EFH Corp. subsidiary holding the capitalized software licensed to Capgemini, and

• $2 million of severance-related charges related to the 2004 restructuring actions.

Interest expense increased $17 million, or 6%, to $286 million in 2006 due to higher average balances of commercial paper outstanding.

Income tax expense totaled $170 million in 2006 compared to $174 million in 2005. The effective tax rate was comparable at 33.1% for both 2006 and 2005.

Net income decreased $7 million, or 2%, to $344 million driven by costs associated with the 2006 cities rate settlement and expenses related to the InfrastruX Energy Services agreement.

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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 years ended December 31, 2007, 2006 and 2005. The net changes in these assets and liabilities, excluding “fair value adjustments”, “other activity” and “reclassification” as described below, represent the pretax effect of mark-to-market accounting on net income for positions in the commodity contract portfolio that are not subject to cash flow hedge accounting (see discussion below and in Note 20 to Financial Statements). For the year ended December 31, 2007, this effect totaled $2.368 billion in unrealized net losses, which represented $2.279 billion in net losses on unsettled positions and $89 million in net losses representing reversals of previously recognized fair values of positions settled in the current period. These positions represent both economic hedging and trading activities.

	Combined (a)			Successor			Predecessor
	Year Ended December 31, 2007			October 11, 2007 through December 31, 2007			January 1, 2007 through October 10, 2007			Year Ended December 31, 2006			Year Ended December 31, 2005
Commodity contract net asset (liability) at beginning of period	$	(23	)	$	(920	)	$	(23	)	$	(56	)	$	23
Fair value adjustments at Merger closing date (b)		144			144			—			—			—
Reclassification at Merger closing date (c)		400			400			—			—			—
Settlements of positions (d)		(89	)		(80	)		(9	)		11			(23	)
Unrealized mark-to-market valuations of positions held at end of period (e)		(2,279	)		(1,476	)		(803	)		22			32
Other activity (f)		(70	)		15			(85	)		—			(88	)
Commodity contract net asset (liability) at end of period	$	(1,917	)	$	(1,917	)	$	(920	)	$	(23	)	$	(56	)

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP presentation.

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

(c) Represents reclassification of fair values of derivatives no longer accounted for as cash flow hedges as of the date of the Merger.

(d) Represents reversals of fair values recognized prior to the beginning of the period to offset gains and losses realized upon settlement of the positions in the current period.

(e) Primarily represents mark-to-market effects of positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”). Also includes an $8 million loss in the Successor period, $231 million in losses and a $30 million gain in the 2007 Predecessor period and $106 million in net losses in 2006 recorded at contract inception dates (see Note 20 to Financial Statements).

(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 20 to Financial Statements), net of a $102 million cost paid related to a structured economic hedge transaction in the long-term hedging program and $74 million in natural gas provided under physical swap transactions. Activity in 2005 included $75 million of natural gas received under physical swap transactions and a $12 million charge related to nonperformance by a coal contract counterparty.

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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 20 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:

	Combined (a)			Successor			Predecessor
	Year Ended December 31, 2007			October 11, 2007 through December 31, 2007			January 1, 2007 through October 10, 2007			Year Ended December 31, 2006		Year Ended December 31, 2005
Unrealized gains/(losses) related to contracts marked-to-market	$	(2,368	)	$	(1,556	)	$	(812	)	$	33	$	9
Ineffectiveness gains/(losses) related to cash flow hedges (b)		90			—			90			239		(27	)
Total unrealized gains (losses) related to commodity contracts	$	(2,278	)	$	(1,556	)	$	(722	)	$	272	$	(18	)

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP presentation.

(b) See Note 20 to Financial Statements.

These amounts are reported in the “risk management and trading activities” component of revenues.

Maturity Table — Following are the components of the net commodity contract liability at December 31, 2007:

	Successor
	Amount
Net commodity contract liability	$	(1,917	)
Premiums paid under option agreements		(103	)
Net receipts of natural gas under physical swap transactions		11
Amount of net liability arising from recognition of fair values	$	(2,009	)

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The following table presents the net commodity contract liability arising from recognition of fair values as of December 31, 2007, scheduled by the source of fair value and contractual settlement dates of the underlying positions. See Note 24 to Financial Statements for fair value disclosures required under SFAS 157.

	Maturity dates of unrealized commodity contract liabilities at December 31, 2007 (Successor)
Source of fair value (a)	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	54		$	(41	)	$	(44	)	$	—		$	(31	)
Prices provided by other external sources		77			(476	)		(923	)		(353	)		(1,675	)
Prices based on models		(79	)		(34	)		(27	)		(163	)		(303	)
Total	$	52		$	(551	)	$	(994	)	$	(516	)	$	(2,009	)
Percentage of total fair value		(3	)%		27	%		50	%		26	%		100	%

(a) Under this analysis, a contract can have more than one source of fair value. In such cases, the value of the contract is segregated by source of value.

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 generally extend through 2012 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 long-term pricing models. In many instances, these contracts can be broken down into their component parts and each component valued separately. Components valued as forward commodity positions are included in the “prices provided by other external sources” category. Components valued as options are included in the “prices based on models” category.

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COMPREHENSIVE INCOME – Continuing Operations

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

	Combined (a)			Successor			Predecessor
	Year Ended December 31, 2007			Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31,
										2006			2005
Net increase (decrease) in fair value of cash flow hedges held at end of period:
Commodities	$	(243	)	$	5		$	(248	)	$	568		$	(47	)
Financing – interest rate swaps		(182	)		(182	)		—			—			—
		(425	)		(177	)		(248	)		568			(47	)
Derivative value net losses (gains) reported in net income that relate to hedged transactions recognized in the period:
Commodities		(135	)		—			(135	)		(23	)		64
Financing – interest rate swaps		6			—			6			8			13
		(129	)		—			(129	)		(15	)		77
Total income (loss) effect of cash flow hedges reported in other comprehensive income from continuing operations	$	(554	)	$	(177	)	$	(377	)	$	553		$	30

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP presentation.

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 20 to Financial Statements.

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FINANCIAL CONDITION

Liquidity and Capital Resources

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

	Combined (a)			Successor			Predecessor
	Year Ended December 31, 2007			Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31,
										2006			2005
Cash flows — operating activities
Net income (loss)	$	(637	)	$	(1,360	)	$	723		$	2,552		$	1,722
Income from discontinued operations, net of tax effect		(25	)		(1	)		(24	)		(87	)		(5	)
Extraordinary loss, net of tax effect		—			—			—			—			50
Cumulative effect of changes in accounting principles, net of tax effect		—			—			—			—			8
Income (loss) from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles		(662	)		(1,361	)		699			2,465			1,775
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Depreciation and amortization		1,252			568			684			893			836
Deferred income tax expense (benefit) – net		(847	)		(736	)		(111	)		756			481
Impairment of natural gas-fueled generation plants		—			—			—			198			—
Customer appreciation bonus charge (net of amounts credited to customers in 2006)		—			—			—			122			—
Net charges related to canceled development of generation facilities (Note 7)		678			2			676			—			—
Net effect of unrealized mark-to-market valuations – losses (gains)		2,278			1,556			722			(272	)		18
Other, net		68			16			52			52			(65	)
Changes in operating assets and liabilities		(952	)		(495	)		(457	)		740			(252	)
Cash provided by (used in) operating activities	$	1,815		$	(450	)	$	2,265		$	4,954		$	2,793
Cash flows — financing activities
Equity financing from Sponsor Group and other investors	$	8,236		$	8,236		$	—		$	—		$	—
Net issuances and redemptions of borrowings, including debt issuance costs, premiums and discounts		27,916			25,629			2,287			(777	)		356
Net repurchases of common stock, preference stock and preferred securities of subsidiaries		(12	)		—			(12	)		(832	)		(1,392	)
Common and preference stock dividends paid		(788	)		—			(788	)		(764	)		(555	)
Excess tax benefit on stock-based incentive compensation		—			—			—			41			28
Settlements of minimum withholding tax liabilities under stock-based incentive compensation plans		(93	)		—			(93	)		—			—
Cash provided by (used in) financing activities	$	35,259		$	33,865		$	1,394		$	(2,332	)	$	(1,563	)
Cash flows — investing activities
Acquisition of EFH Corp.	$	(32,694	)	$	(32,694	)	$	—		$	—		$	—
Capital expenditures, including purchases of mining- related assets and nuclear fuel		(3,224	)		(707	)		(2,517	)		(2,297	)		(1,104	)
Proceeds from TCEH senior secured letter of credit facility deposited with bank		(1,250	)		(1,250	)		—			—			—
Reduction of restricted cash		215			13			202			—			—
Proceeds from pollution control revenue bonds deposited with trustee		—			—			—			(240	)		—
Other		107			75			32			(127	)		66
Cash used in investing activities	$	(36,846	)	$	(34,563	)	$	(2,283	)	$	(2,664	)	$	(1,038	)
Cash provided by (used in) discontinued operations	$	28		$	(7	)	$	35		$	30		$	(261	)
Net change in cash and cash equivalents	$	256		$	(1,155	)	$	1,411		$	(12	)	$	(69	)

(a) See “Presentation and Analysis of Results” above for explanation of this non-GAAP presentation.

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The $3.139 billion decrease in cash provided by operating activities in 2007 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 charges related to canceled development of generation facilities;

• an unfavorable change of $1.747 billion in net margin deposits due to the effect of higher forward natural gas prices, primarily related to the long-term hedging program ($614 million related to the Successor periods that was largely funded by the Commodity Collateral Posting Facility), and

• an unfavorable change in working capital (accounts receivable, accounts payable and inventories) balances of $402 million primarily due to the effects of lower natural gas prices, as cash flows in 2006 included the collection of higher wholesale natural gas and electricity receivables that resulted from higher prices in late 2005.

The $2.161 billion increase in cash provided by operating activities in 2006 reflected:

• higher operating earnings after taking into account noncash items;

• a favorable change of $503 million in net margin deposits, primarily reflecting amounts received from counterparties related to natural gas positions in the long-term hedging program, and

• a favorable change of $293 million in working capital (accounts receivable, accounts payable and inventories) driven by higher wholesale natural gas and electricity receivables in 2005 due to higher prices in the fourth quarter of 2005.

The year-to-year increases in capital expenditures over the three-year period ended December 31, 2007 were driven by spending related to the development and construction of new generation facilities.

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $50 million, $153 million, $63 million and $60 million for the period from October 11, 2007 through December 31, 2007, the period from January 1, 2007 through October 10, 2007, and the years 2006 and 2005, respectively. For the 2007, 2006 and 2005 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 2007 Successor period, 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.

Liquidity Needs, Including Capital Expenditures —Capital expenditures, including capitalized interest, for 2008 are expected to total approximately $3.0 billion and include:

• $775 to $875 million for investment in Oncor’s transmission and distribution infrastructure;

• $2.2 billion for investments in TCEH generation facilities, including:

^¡ approximately $1.3 billion for construction of one generation unit at Sandow and two generation units and mine development;

^¡ approximately $700 million for major maintenance capital, primarily in existing generation operations, and

^¡ approximately $200 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 or operating cash flows. 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 17 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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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. While the pension and post-retirement plan investments include some subprime-related securities, a decline in the fair value of such investments would not be material.

As of December 31, 2007, EFH Corp. and its subsidiaries had no debt that was insured. TCEH had $445.5 million of tax-exempt long-term debt backed by $455 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.

Credit Facilities — As of March 14, 2008, TCEH had $2.466 billion of liquidity available under committed revolving credit facilities for working capital and other general corporate purposes, approximately $1.831 billion of liquidity available under the committed Delayed Draw Term Loan facility to fund certain specified capital expenditures and related expenses (of which $270 million represents expenditures already incurred for which funding is available), and unlimited availability under the committed TCEH Commodity Collateral Posting Facility. As of March 14, 2008, Oncor had $620 million of liquidity available under its committed credit facility for working capital and other general corporate purposes. See Note 17 to Financial Statements for discussion of the facilities.

Liquidity Effects of Risk Management and Trading Activities — Risk management and trading transactions typically require collateral to support potential future payment obligations. In particular, commodity transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument is out-of-the-money to such counterparty. EFH Corp. and its subsidiaries use cash and letters of credit and other collateral structures to satisfy such collateral obligations. In addition, in connection with the Merger, TCEH entered into the TCEH Commodity Collateral Posting Facility, which is an uncapped senior secured revolving credit facility that will fund the cash collateral posting requirements due to trading counterparties for a significant portion of the positions in the long-term hedging program not otherwise secured by a first-lien in the assets of TCEH. This facility is secured on a pari passu basis with the TCEH Senior Secured Facilities. See Note 17 to Financial Statements for more information about this facility. The aggregate principal amount of this facility is determined by the out-of-the-money exposure, regardless of the amount of such exposure, on a portfolio of certain natural gas swap transactions. At February 29, 2008, approximately 94% of EFH Corp.’s hedging transactions were secured by a first-lien interest in the assets of TCEH (including the transactions covered by the TCEH Commodity Collateral Posting Facility) that is pari passu with the TCEH Senior Secured Facilities.

As of February 29, 2008, subsidiaries of EFH Corp. have received or posted cash and letters of credit for risk management and trading activities as follows:

• $210 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $672 million received as of December 31, 2006;

• $884 million in cash has been posted with counterparties for over-the-counter and other non-exchanged cleared transactions, as compared to $2 million received as of December 31, 2006, and

• $694 million in letters of credit have been posted with counterparties, as compared to $455 million posted as of December 31, 2006.

Borrowings under the TCEH Commodity Collateral Posting Facility funded $1.4 billion of the above cash postings.

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 variation 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 used by EFH Corp. and its subsidiaries for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities. 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.

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As a result of 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 March 14, 2008, for each $1.00 per MMBtu increase in natural gas prices, EFH Corp.’s cash collateral posting requirements associated with the long-term hedging program would increase by approximately $1.0 billion. Of this amount, approximately $0.9 billion would be funded by the TCEH Commodity Collateral Posting Facility.

New Financing Arrangements —See Note 17 to Financial Statements for details of financing arrangements entered into at the Merger closing date to fund the Merger and provide liquidity subsequent to the Merger.

Covenants and Restrictions under Financing Arrangements —Each of the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes and Senior Toggle Notes and the EFH Corp. Senior Notes and Senior Toggle 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 17 to Financial Statements for additional discussion of the covenants contained in these financing arrangements.

When the term “Adjusted EBITDA” 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 indentures governing the EFH Corp. Notes. Adjusted EBITDA, as defined in the indentures governing the EFH Corp. Notes, for the year ended December 31, 2007 totaled $4.9 billion for EFH Corp. See Exhibit 99(b) for a reconciliation of net income to Adjusted EBITDA for EFH Corp. for the years ended December 31, 2007 and 2006. See glossary for definition of Adjusted EBITDA.

Maintenance Covenant—Under the TCEH Senior Secured Facilities, TCEH and its restricted subsidiaries will be 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 cannot exceed 7.25 to 1.00 for the first measurement period ending September 30, 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 has the right to cure its non-compliance by soliciting a cash investment in an amount necessary to become compliant.

Debt Incurrence Covenant— 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 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 EFH Corp. and its restricted subsidiaries is at least 2.0 to 1.0 or such incurrence or issuance is otherwise permitted 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. In addition, under this indenture, TCEH and its restricted subsidiaries are not permitted to incur indebtedness or issue certain classes of 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 in the 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.

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 credit agreement) is at least 2.0 to 1.0 or such incurrence is otherwise permitted in the TCEH Senior Secured Facilities.

Under the indenture governing the TCEH Notes, TCEH and substantially all of its subsidiaries are not permitted to incur indebtedness or issue certain classes of stock unless, on a pro forma basis, after giving effect to such incurrence or issuance, the fixed charge coverage ratio (as defined in the applicable debt agreements) 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 in the applicable debt agreements. 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.

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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 certain dividends, equity repurchases, 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 the indenture) and unless a restricted payment coverage ratio (as defined in the 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 under the indenture. The restricted payment coverage ratio 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. However, in the case of payments to the Sponsor Group, the restricted payment coverage ratio 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). Notwithstanding any other provisions of the indenture, EFH Corp. or its restricted subsidiaries may not pay any dividends or other returns to the Sponsor Group 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. 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.

Under the TCEH Senior Secured Facilities and indentures 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.

Long-Term Debt-Related Activity — See Note 17 to Financial Statements for further detail of long-term debt and other financing arrangements, including the long-term debt EFH Corp. issued or reacquired or on which it made scheduled principal payments in 2007.

Capitalization — The capitalization ratios of EFH Corp. at December 31, 2007, consisted of 85.2% long-term debt, less amounts due currently, and 14.8% common stock equity. Total debt to capitalization, including short-term debt, was 85.9% and 85.5% at December 31, 2007 and 2006, respectively.

Pension Plan Funding — In August 2006, the Pension Protection Act of 2006 (the Act) was signed into law. The Act which will be phased in over the next few years is expected to increase pension plan funding and require additional plan disclosures in regulatory filings and to plan participants. Pension plan calendar year funding for EFH Corp. is expected to total $155 million in 2008 and $74 million in 2009, including the effects of the Act. Contributions to the pension plan in 2007 totaled $4 million.

Income Tax Payments — Excluding the effects of any potential transactions or audit settlements with the IRS, federal income tax refunds of 2007 tax payments are estimated to total approximately $98 million in 2008. Federal tax payments totaled $271 million in 2007 and $220 million in 2006.

As discussed in Note 12 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 none are expected in the next 12 months.

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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 $363 million and $627 million at December 31, 2007 and 2006, respectively. The funding decrease reflects $116 million of retail customer deposits reducing funding availability due to the downgrade in TCEH’s credit ratings, lower accounts receivable balances driven by price discounts and Oncor’s exit from the program. See Note 16 to Financial Statements for a more complete description of the program including the amendments made in connection with the Merger, 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.

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 minimum net worth covenants. As of December 31, 2007, EFH Corp.’s subsidiaries were in compliance with all such applicable covenants.

Credit Ratings — The rating agencies assign issuer credit ratings for EFH Corp. and its subsidiaries. The issuer credit ratings as of March 14, 2008 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-, Ba1 and BBB- by S&P, Moody’s 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 March 21, 2008 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)	BBB-	Ba1	BBB
Oncor (Senior Unsecured)	BBB-	Ba1	BBB-

(a) EFH Corp. Cash Pay Notes and EFH Corp. Toggle Notes

(b) TCEH Cash Pay Notes and TCEH Toggle Notes

All of the senior unsecured ratings for EFH Corp., EFC Holdings, and TCEH reflect multi-notch downgrades from all rating agencies as a result of the significant amount of debt incurred by EFH Corp. and TCEH in connection with the Merger in October 2007. The ratings for Oncor’s senior unsecured debt were downgraded two notches by Moody’s and one notch by Fitch. S&P affirmed the existing rating of Oncor’s senior unsecured debt. While Oncor currently has no senior secured indebtedness, once its revolving credit facility and its existing long-term debt become secured, the Oncor senior secured ratings above would apply.

All three rating agencies placed the ratings for EFH Corp. and its subsidiaries on “stable outlook”, with the exception of S&P, which placed Oncor’s rating on “developing outlook”.

On March 21, 2008, S&P assigned recovery ratings to the unsecured debt issued by EFH Corp., EFC Holdings and TCEH. As a result, the ratings on the EFH Corp. Cash Pay Notes and EFH Corp. Toggle Notes were raised one notch to B- from CCC+. In addition, ratings on EFC Holdings’ junior subordinated debt issues were raised to CCC from CCC-.

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EFH Corp. currently intends to sell 20% minority stake in Oncor to further enhance Oncor’s separation from the Texas Holding Group. Should the sale not be completed, Oncor believes that its long-term debt ratings could be adversely affected, including a downgrade of as much as two notches by one of the rating agencies. Similarly, if the sale is completed as intended, Oncor believes that its long-term debt ratings could be positively affected, including an upgrade of as much as two notches by one of the rating agencies.

A rating reflects only the view of a rating agency, and is not a recommendation to buy, sell or hold securities. Any rating 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 — Based upon terms of certain retail and wholesale commodity contracts, as of February 29, 2008 TCEH could have been required to post up to $162 million in additional collateral support.

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 February 29, 2008, TCEH has posted collateral support to the applicable utilities in an aggregate amount equal to $24 million, with $14 million of this amount posted for the benefit of Oncor.

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 maintains equity in an amount that exceeds the minimum required by PUCT rules. As of March 14, 2008, the amount of customer deposits received from customers held by TCEH’s REP subsidiaries totaled approximately $123 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 the Luminant entities’ 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 totaling $91 million as of December 31, 2007 (which is subject to periodic adjustments).

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 will 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 fall below investment grade. See Note 10 to Financial Statements for additional information about the stipulation.

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

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.

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A default by TCEH or any restricted subsidiary in respect of indebtedness, excluding indebtedness relating to the trade 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 ($21.85 billion at March 14, 2008) under such facility 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.

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 and any affiliate of TCEH acting as collection agent under the program. TXU Receivables Company and EFH Corporate Services Company (formerly TXU Business 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 in an amount equal to or greater than $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 $15.05 billion 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 ($1.38 billion at March 14, 2008) 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, 2007 (see Note 17 to Financial Statements for additional disclosures regarding these long-term debt and noncancelable 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)	$	468	$	843	$	2,036	$	36,523	$	39,870
Long-term debt – interest (b)		3,157		6,246		6,108		11,154		26,665
Operating and capital leases (c)		79		154		172		395		800
Obligations under commodity purchase and services agreements (d)		3,077		3,290		2,187		1,396		9,950
Total contractual cash obligations (e)	$	6,781	$	10,533	$	10,503	$	49,468	$	77,285

(a) Excludes capital lease obligations and fair value discounts related to purchase accounting.

(b) Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interest rate swaps are calculated based on interest rates in effect at December 31, 2007.

(c) Includes short-term noncancelable 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 2007 price remained in effect for all periods except where contractual price adjustment or index-based prices were specified.

(e) Table does not include estimated 2008 funding of the pension and other postretirement benefits plans totaling approximately $204 million. It also does not include cancellable contracts associated with the construction of new generation facilities with obligations totaling approximately $1.6 billion through 2010. See Note 18 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 cancelable without payment of a substantial cancellation penalty;

• Oncor’s 2006 cities rate settlement agreement, which is discussed in Note 11 to Financial Statements;

• Oncor’s one-time credit of $72 million to REP customers pursuant to stipulation approved by the PUCT as discussed in Note 10 to Financial Statements;

• employment contracts with management and

• liabilities related to uncertain tax positions discussed in Note 12 to Financial Statements.

Guarantees — See Note 18 to Financial Statements for details of guarantees.

OFF BALANCE SHEET ARRANGEMENTS

EFH Corp. has established an accounts receivable securitization program. See discussion above under “Sale of Receivables” and in Note 16 to Financial Statements.

EFH Corp. has an ownership interest in the Capgemini outsourcing business. See Note 21 to Financial Statements.

Also see Note 18 to Financial Statements regarding guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 18 to Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

See Notes 1, 12, 22 and 24 to Financial Statements for a discussion of changes in accounting standards.

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REGULATION AND RATES

Regulatory Investigations

See Note 18 to Financial Statements for discussion of regulatory investigations.

2007 Texas Legislative Session

The Texas Legislature convened its regular biennial session on January 9, 2007 and adjourned on May 28, 2007. The session was not a “sunset” session for the PUCT, so there was no requirement that the Legislature consider any electric industry-related bills. However, various measures pertaining to the electric industry were considered. The primary measures that were under consideration and would have materially affected EFH Corp.’s businesses and potentially the Merger were ultimately not enacted. New PURA provisions were enacted that ensure the PUCT shall have authority to enforce commitments made in a filing under PURA Section 14.101 on or after May 1, 2007 (such as the filing made by Texas Holdings and Oncor in April 2007 and approved by the PUCT in February 2008).

REP Certification Rulemaking

In October 2007, the PUCT voted to approve revisions to its REP certification rule. The approved revisions provide that REPs that serve at least one million Texas residential customers are subject to additional or different financial requirements as determined by the PUCT unless they meet one of the following specified additional financial requirements: (1) a credit rating of “BBB” for S&P or “Baa2” for Moody’s, or their financial equivalent (satisfied through the REP’s own credit rating, a guaranty of a parent or controlling shareholder with the required credit rating, or a bond, guaranty or corporate commitment of another company with the required credit rating); (2) an increased amount of equity (defined as assets in excess of liabilities); or (3) an increased amount of unused cash resources. The additional financial requirements have not significantly increased TCEH’s cost of doing business.

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;

• to operate a voluntary day-ahead energy market;

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

• to use nodal energy prices for resources;

• to provide information for energy trading hubs by aggregating nodes;

• to use zonal prices for loads, and

• to 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, which 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. 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 on October 1, 2006. Additionally, at its January 15, 2008 meeting, the ERCOT Board of Directors agreed to request an increase in the surcharge to be effective June 1, 2008. ERCOT filed this request at the PUCT in March 2008. EFH Corp. expects that the annual impact of the surcharge will 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.

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Price-to-Beat Rates

As a result of the legislation that restructured the electric utility industry in Texas to provide for retail competition (1999 Restructuring Legislation), effective January 1, 2002, REPs (such as TXU Energy) affiliated with electricity delivery utilities were required to charge price-to-beat rates (adjusted for fuel factor changes), established by the PUCT, to residential and small business customers located in their historical service territories. In accordance with certain phase out provisions of the legislation, beginning January 1, 2005, TXU Energy offered rates different from the price-to-beat rate to all customer classes, but was required to make the price-to-beat rate available for residential and small business customers in its historical service territory until January 1, 2007. Under PUCT rules and because of rising natural gas prices, in 2005 TXU Energy petitioned and received approval from the PUCT for price-to-beat rate increases implemented as follows (percentage represents increase in the average monthly residential bill):

• 10% and 12% in May and October of 2005, respectively. The latter reflected a voluntary discount that expired December 31, 2005, and

• 12% in January of 2006 representing the expiration of the voluntary discount.

As of January 1, 2007, TXU Energy is no longer required to offer the price-to-beat rate to any of its customer classes.

Oncor Matters with the PUCT

Stipulation Approved by the PUCT —In April 2007, Oncor and Texas Holdings (together, the Applicants) filed a Joint Report and Application (Report) with the PUCT pursuant to Section 14.101(b) of PURA and PUCT SUBST. R.25.75. These rules at that time required that a transaction involving the sale of more than 50% of the stock of a public utility be reported to the PUCT within a reasonable time subsequent to consummation of the transaction and that the PUCT shall determine whether the transaction is consistent with the public interest standards set out therein. The Report contained commitments that took effect upon the closing of the Merger. Such commitments include: maintenance of specified Oncor debt-to-equity ratios, minimum Oncor capital expenditure levels, increased spending on demand side management/energy efficiency programs over the amount in Oncor’s rates, minimum five year continued majority ownership by the Sponsor Group and covenants not to incur any indebtedness and not to guarantee or use Oncor assets to secure any affiliate indebtedness incurred to finance the Merger. In connection with a proceeding resulting from the filing of the Report, several parties, including Oncor, the PUCT staff, and certain interveners agreed on the terms of a stipulation. In January 2008, the PUCT approved the stipulation, and the final order was entered in February 2008. The stipulation requires the filing of a rate case by Oncor no later than July 1, 2008, based on a test year ended December 31, 2007. As a result of this commitment, EFH Corp. expects the PUCT to dismiss the rate case filed by Oncor in August 2007, which was based on a test year ended December 31, 2006. See Note 10 to Financial Statements for discussion of additional provisions and financial statement effects of the stipulation.

Advanced Meter Rulemaking — In 2005, the Texas Legislature passed legislation that authorized electric utilities to impose 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 summer of 2008. Oncor intends to file a rate surcharge case on or before July 1, 2008 to request recovery of its estimated future investment for advanced metering deployment.

At December 31, 2007, Oncor had installed approximately 600,000 advanced meters in its service territory at a capital cost of approximately $125 million. Oncor intends to seek recovery of the costs of these meters in the general rate case to be filed with the PUCT no later than July 1, 2008 if recovery is not sought in the rate surcharge case.

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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 2008, an application was filed to increase the TCRF, which was administratively approved on February 28, 2008 and became effective March 1, 2008. This increase is expected to increase annualized revenues by $12 million.

In February 2008, Oncor filed an application for an interim update of its wholesale transmission rate. 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.

Competitive Renewable Energy Zones — 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.

The PUCT also opened a project to evaluate potential transmission service providers who are interested in constructing the designated transmission facilities. In connection with this project, Oncor indicated to the PUCT its interest in constructing any designated transmission facilities, particularly those within its traditional service territory and those that interconnect with Oncor’s transmission facilities.

In October 2007, the PUCT issued its interim order in the Competitive Renewable Energy Zones (CREZ) docket. Within six months of the date of the interim order, ERCOT will file the results of a CREZ Transmission Optimization Study. The study will include four scenarios of wind capacity, ranging from 10,000 MW to 22,806 MW. The PUCT will then determine the major transmission improvements needed to support the wind resources and select the transmission service providers that will construct the facilities. Oncor cannot predict the amount of transmission facilities in competitive renewable energy zones, if any, that it will construct.

In the fourth quarter of 2007, the PUCT issued its Proposal for Publication for a new rule regarding the Selection of Transmission Service Providers to establish a process for entities interested in constructing transmission improvements to submit expressions of interest to the PUCT. The rule also establishes the procedure whereby the PUCT selects the entities responsible for constructing the transmission improvements, and specifies requirements to ensure that such entities complete the ordered improvements in a timely and cost-effective manner. This proposed new rule would require the PUCT to develop a plan to construct transmission capacity necessary to deliver to electricity customers, the electric output from renewable energy technologies in CREZ and to consider the level of financial commitment by generators for each CREZ in determining whether to grant a Certificate of Convenience and Necessity. The rulemaking proceeding is in a formal comment phase and a required Administrative Procedures Act hearing was held on February 12, 2008.

In March 2008, the PUCT issued an Order Requiring Settlement Conference regarding the selection of transmission service providers to construct facilities necessary to serve CREZ. The Order specifies the intent of the PUCT to continue the existing rulemaking process, but also initiate a parallel process by ordering a settlement conference regarding the selection of transmission service providers for the CREZ transmission facilities. All entities that are interested in constructing and operating CREZ transmission facilities are required to participate in the settlement conference. An initial settlement conference meeting was held on March 27, 2008. Oncor will continue to participate in the settlement conference.

Summary

Although EFH Corp. cannot predict future regulatory or legislative actions or any changes in economic and securities market conditions, no changes are expected in trends or commitments, other than those discussed in this report, which might 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 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’s wholesale operation manages the commodity price, counterparty credit and 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 daily by risk management groups that operate and report 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, credit review and approval, operational and market risk measurement, validation of transaction capture, portfolio valuation and daily portfolio reporting, including mark-to-market valuation, VaR and other risk measurement metrics.

EFH Corp. has a corporate risk management organization that is headed by a Chief Risk Officer. The Chief Risk Officer, through his designees, enforces all 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. Valuation adjustments are established in recognition that certain risks exist until full delivery and settlement of energy has occurred, counterparties have fulfilled their financial commitments and related contracts have either matured or are settled. 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 discussion above under “Significant Developments” for an update of the program, including potential effects on reported results.

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

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

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

	Year Ended December 31, 2007		Year Ended December 31, 2006
Month-end average Trading VaR:	$	9	$	12
Month-end high Trading VaR:	$	14	$	30
Month-end low Trading VaR:	$	6	$	5

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

	Year Ended December 31, 2007		Year Ended December 31, 2006
Month-end average MtM VaR:	$	1,081	$	149
Month-end high MtM VaR:	$	1,576	$	391
Month-end low MtM VaR:	$	322	$	5

Earnings at Risk (EaR)— This measurement estimates the potential reduction of fair value of expected pretax earnings for the years 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). For this purpose, cash flow hedges are also included with transactions that are not marked-to-market in net income. A 95% confidence level and a five to 60 day holding period are assumed in determining EaR.

	Year Ended December 31, 2007		Year Ended December 31, 2006
Month-end average EaR:	$	1,070	$	156
Month-end high EaR:	$	1,559	$	387
Month-end low EaR:	$	318	$	21

The increases in the risk measures (MtM VaR and EaR) above reflected the dedesignation of positions in the long-term hedging program as cash flow hedges for accounting purposes in March 2007, which resulted in the positions subsequently being marked-to-market in net income, and an increase in the number of positions in the program.

Interest Rate Risk

The table below provides information concerning EFH Corp.’s financial instruments as of December 31, 2007 and 2006 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. 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 17 to Financial Statements for a discussion of changes in debt obligations.

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	Expected Maturity Date
	(millions of dollars, except percentages)																		Successor					Predecessor
	2008			2009			2010			2011			2012			There- After			2007 Total Carrying Amount			2007 Total Fair Value		2006 Total Carrying Amount			2006 Total Fair Value
Long-term debt (including current maturities)
Fixed rate debt amount (a)	$	303		$	250		$	237		$	745		$	919		$	17,160		$	19,614		$	18,987	$	10,486		$	10,669
Average interest rate		5.83	%		5.36	%		5.04	%		5.37	%		6.11	%		9.18	%		8.74	%				6.18	%		—
Variable rate debt amount	$	165		$	170		$	186		$	186		$	186		$	19,363		$	20,256		$	19,909	$	615		$	639
Average interest rate		8.40	%		8.40	%		8.39	%		8.39	%		8.39	%		8.29	%		8.29	%				4.27	%		—
Total debt	$	468		$	420		$	423		$	931		$	1,105		$	36,523		$	39,870		$	38,896	$	11,101		$	11,308
Debt swapped to variable:
Amount	$	200		$	—		$	—		$	—		$	—		$	—		$	200				$	2,800
Average pay rate		7.48	%		—			—			—			—			—			7.48	%				6.95	%
Average receive rate		6.38	%		—			—			—			—			—			6.38	%				5.89	%
Debt swapped to fixed:
Amount	$	—		$	1,250		$	500		$	600		$	2,600		$	10,100		$	15,050				$	300
Average pay rate		—			7.33	%		7.43	%		7.57	%		7.99	%		8.15	%		8.01	%				5.18	%
Average receive rate		—			8.40	%		8.40	%		8.40	%		8.40	%		8.40	%		8.40	%				5.37	%

(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 17 to Financial Statements for details concerning long-term debt subject to mandatory tender for remarketing.

In the fourth quarter of 2007, interest rate swaps dedesignated as fair value hedges related to $700 million principal amount of debt were settled upon early extinguishment of the underlying debt.

As of March 14, 2008, the potential reduction of annual pretax earnings due to a one-point increase in interest rates totaled approximately $38 million, taking into account the interest rate swaps in effect.

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 require an evaluation of 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 documented processes for monitoring and managing credit exposure of its businesses including methodologies to analyze counterparties’ financial strength, measurement of current and potential future credit 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 preset limits and analyzed to assess potential credit exposure. This evaluation results in establishing credit limits or collateral requirements prior to entering into an agreement with a counterparty that creates credit exposure. Additionally, EFH Corp. has established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Any prospective material adverse change in the payment history or financial condition of a counterparty or downgrade of its credit quality will 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 $2.116 billion at December 31, 2007.

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Gross assets subject to credit risk as of December 31, 2007 include $499 million in accounts receivable from the retail sale of electricity to residential and small business customers. 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 and market or operational conditions.

Most of the remaining credit exposure is with large business retail customers and 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, 2007, the exposure to credit risk from these customers and counterparties totaled $1.403 billion taking into account standardized master netting contracts and agreements described above and $21 million in credit collateral (cash, letters of credit and other security interests) held by EFH Corp. subsidiaries.

Of this $1.403 billion net exposure, 74% 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.

In addition, Oncor has exposure to credit risk totaling $215 million at December 31, 2007, of which $159 million is arising from potential nonperformance by nonaffiliated REPs. This exposure consists almost entirely of noninvestment grade trade accounts receivable. Oncor does not have any customers that represent more than 10% of the nonaffiliated trade accounts receivable at December 31, 2007.

The following table presents the distribution of credit exposure as of December 31, 2007, for retail trade accounts receivable from large business customers, wholesale trade accounts receivable and net asset positions arising from hedging and trading activities by investment grade and noninvestment grade, credit quality and maturity.

										Net Exposure by Maturity
	Exposure before Credit Collateral			Credit Collateral			Net Exposure			2 years or less		Between 2-5 years		Greater than 5 years		Total
Investment grade	$	1,035		$	—		$	1,035		$	593	$	109	$	333	$	1,035
Noninvestment grade		389			21			368			254		31		83		368
Totals	$	1,424		$	21		$	1,403		$	847	$	140	$	416	$	1,403
Investment grade		73	%		—	%		74	%
Noninvestment grade		27	%		100	%		26	%

Approximately 60% of the net $1.403 billion credit exposure has a maturity date of two years or less. 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 three counterparties each having an exposure greater than 10% of the net $1.403 billion credit exposure. These three counterparties represented 15%, 12% and 10%, respectively, of the net exposure. EFH Corp. views exposure to these three counterparties to be within an acceptable level of risk tolerance as they are rated investment grade; however, this concentration increases the risk that a default would have a material effect on EFH Corp.’s net income and cash flows.

EFH Corp.’s subsidiaries are exposed to credit risk related to its long-term hedging program. Of the transactions in the program, over 94% of the volumes are with counterparties with an A credit rating or better, and 100% are at least investment grade.

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Additionally, under the long-term hedging program, EFH Corp. has potential credit risk exposure concentration related to a limited number of counterparties. The hedge transactions with these counterparties contain certain credit rating provisions that would require the counterparties to post collateral in the event of significant declines in natural gas prices and a material downgrade in the credit rating of the counterparties. EFH Corp. views the potential concentration of risk with these counterparties to be within an acceptable risk tolerance due to the strong financial profile of the counterparties and their respective A or above credit rating.

FORWARD-LOOKING STATEMENTS

This report and other presentations made by EFH Corp. contain “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. 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 and cash distribution policy, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power production 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”, “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 discussed 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:

• 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 given the price protection and price cuts;

• 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;

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• 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 future executive compensation payments;

• significant changes in critical accounting policies;

• actions by credit rating agencies;

• 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, 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 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.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of Energy Future Holdings Corp. (formerly TXU Corp.) and subsidiaries (the “Company”) as of December 31, 2007 (successor) and 2006 (predecessor), and the related statements of consolidated income (loss), comprehensive income (loss), cash flows and shareholders’ equity for the period from October 11, 2007 through December 31, 2007 (successor), the period from January 1, 2007 through October 10, 2007 (predecessor) and for the years ended December 31, 2006 and 2005 (predecessor). Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Energy Future Holdings Corp. and subsidiaries at December 31, 2007 (successor) and 2006 (predecessor), and the results of their operations and their cash flows for the period from October 11, 2007 through December 31, 2007 (successor), the period from January 1, 2007 through October 10, 2007 (predecessor) and for the years ended December 31, 2006 and 2005 (predecessor), in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, the Company 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.

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, 2007, based on the criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 31, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Dallas, Texas

March 31, 2008

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Millions of Dollars)

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007
							Year Ended December 31,
							2006			2005
Operating revenues	$	502		$	7,490		$	10,856		$	10,662
Costs and expenses:
Fuel, purchased power costs and delivery fees		644			2,381			2,784			4,261
Operating costs		306			1,107			1,373			1,425
Depreciation and amortization		415			634			830			776
Selling, general and administrative expenses		216			691			819			781
Franchise and revenue-based taxes		93			282			390			364
Other income (Note 15)		(14	)		(69	)		(121	)		(151	)
Other deductions (Note 15)		61			841			269			45
Interest income		(24	)		(56	)		(46	)		(48	)
Interest expense and related charges (Note 28)		839			671			830			802
Total costs and expenses		2,536			6,482			7,128			8,255
Income (loss) from continuing operations before income taxes, extraordinary loss and cumulative effect of changes in accounting principles		(2,034	)		1,008			3,728			2,407
Income tax expense (benefit)		(673	)		309			1,263			632
Income (loss) from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles		(1,361	)		699			2,465			1,775
Income from discontinued operations, net of tax effect (Note 4)		1			24			87			5
Extraordinary loss, net of tax effect (Note 5)		—			—			—			(50	)
Cumulative effect of changes in accounting principles, net of tax effect (Note 6)		—			—			—			(8	)
Net income (loss)	$	(1,360	)	$	723		$	2,552		$	1,722
Preference stock dividends		—			—			—			10
Net income (loss) available for common stock	$	(1,360	)	$	723		$	2,552		$	1,712

See Notes to Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Millions of Dollars)

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007
							Year Ended December 31,
							2006			2005
Components related to continuing operations:
Income (loss) from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles	$	(1,361	)	$	699		$	2,465		$	1,775
Other comprehensive income (loss), net of tax effects:
Reclassification of pension and other retirement benefit costs (net of tax (expense) benefit of $5, $(19), $— and $—) (Note 22)		(57	)		49			—			—
Minimum pension liability adjustments (net of tax (expense) benefit of $—, $—, $(38) and $25)		—			—			71			(46	)
Cash flow hedges:
Net increase (decrease) in fair value of derivatives held at end of period (net of tax (expense) benefit of $97, $133, $(304) and $24)		(177	)		(248	)		568			(47	)
Derivative value net (gains) losses related to hedged transactions recognized during the period and reported in net income (net of tax (expense) benefit of $—, $(69), $(8) and $42)		—			(129	)		(15	)		77
Total effect of cash flow hedges		(177	)		(377	)		553			30
Total adjustments to net income from continuing operations		(234	)		(328	)		624			(16	)
Comprehensive income (loss) from continuing operations		(1,595	)		371			3,089			1,759
Comprehensive income from discontinued operations		1			24			87			5
Extraordinary loss, net of tax effect		—			—			—			(50	)
Cumulative effect of changes in accounting principles, net of tax effect		—			—			—			(8	)
Comprehensive income (loss)	$	(1,594	)	$	395		$	3,176		$	1,706

See Notes to Financial Statements.

103

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007
							Year Ended December 31,
							2006			2005
Cash flows — operating activities
Net income (loss)	$	(1,360	)	$	723		$	2,552		$	1,722
Income from discontinued operations, net of tax effect		(1	)		(24	)		(87	)		(5	)
Extraordinary loss, net of tax effect		—			—			—			50
Cumulative effect of changes in accounting principles, net of tax effect		—			—			—			8
Income (loss) from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles		(1,361	)		699			2,465			1,775
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Depreciation and amortization		568			684			893			836
Deferred income tax expense (benefit) – net		(736	)		(111	)		756			481
Impairment of natural gas-fueled generation plants		—			—			198			—
Asset writedown charges		—			—			6			11
Customer appreciation bonus charge (net of amounts credited to customers in 2006)		—			—			122			—
Net charges related to canceled development of generation facilities (Note 7)		2			676			—			—
Write-off of deferred transaction costs (Note 15)		—			38			—			—
Credit related to impaired leases (Note 8)		—			(48	)		(2	)		(16	)
Net gains on sale of assets, including amortization of deferred gains		(1	)		(40	)		(69	)		(89	)
Net effect of unrealized mark-to-market valuations – losses (gains)		1,556			722			(272	)		18
Bad debt expense		12			46			68			56
Stock-based incentive compensation expense		—			27			27			32
Recognition of losses on dedesignated cash flow hedges		—			10			12			20
Recognition of gain (loss) on dedesignated fair value hedges		—			5			(6	)		(10	)
Charge related to coal contract counterparty claim		—			—			—			12
Net equity loss from unconsolidated affiliate		—			1			14			—
Change in regulatory-related liabilities		3			—			1			(81	)
Other, net		2			13			1			—
Changes in operating assets and liabilities:
Accounts receivable – trade		309			(200	)		337			(335	)
Impact of accounts receivable sales program		(336	)		72			(44	)		197
Inventories		(5	)		(7	)		(21	)		(55	)
Accounts payable – trade		(264	)		81			(219	)		(47	)
Commodity and other derivative contractual assets and liabilities		18			(185	)		—			67
Margin deposits – net		(614	)		(569	)		564			61
Other – net assets		284			(89	)		(92	)		35
Other – net liabilities		113			440			215			(175	)
Cash provided by (used in) operating activities from continuing operations	$	(450	)	$	2,265		$	4,954		$	2,793

See Notes to Financial Statements.

104

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.)

(Millions of Dollars)

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007
							Year Ended December 31,
							2006			2005
Cash flows — financing activities
Issuances of securities:
Equity financing from Sponsor Group and other investors	$	8,236		$	—		$	—		$	—
Merger-related debt financing		42,732			1,800			—			—
Pollution control revenue bonds		—			—			243			180
Common stock		—			1			180			83
Retirements/repurchases of securities:
Equity-linked debt		—			—			(179	)		(106	)
Pollution control revenue bonds		—			(143	)		(259	)		(39	)
Merger-related debt repurchases		(15,314	)		—			—			—
Other long-term debt		(81	)		(302	)		(1,253	)		(230	)
Preference stock		—			—			—			(300	)
Preferred securities of subsidiaries		—			—			—			(38	)
Common stock		—			(13	)		(960	)		(1,099	)
Increase (decrease) in short-term borrowings:
Commercial paper		—			(1,296	)		939			358
Bank borrowings		(722	)		2,245			(245	)		230
Cash dividends paid:
Common stock		—			(788	)		(764	)		(544	)
Preference stock		—			—			—			(11	)
Settlements of minimum withholding tax liabilities under stock-based compensation plans		—			(93	)		(52	)		(38	)
Excess tax benefit on stock-based incentive compensation		—			—			41			28
Debt issuance and redemption costs, including premiums and discounts		(986	)		(17	)		(23	)		(37	)
Cash provided by (used in) financing activities from continuing operations		33,865			1,394			(2,332	)		(1,563	)
Cash flows — investing activities
Acquisition of EFH Corp.		(32,694	)		—			—			—
Capital expenditures		(684	)		(2,341	)		(2,180	)		(1,047	)
Nuclear fuel		(23	)		(54	)		(117	)		(57	)
Purchase of mining-related assets		—			(122	)		—			—
Proceeds from sale of assets		86			71			20			77
Purchase of lease trust		—			—			(69	)		—
Reduction of restricted cash		13			202			—			—
Proceeds from sales of nuclear decommissioning trust fund securities		831			602			207			191
Investments in nuclear decommissioning trust fund securities		(835	)		(614	)		(223	)		(206	)
Proceeds from pollution control revenue bonds deposited with trustee		—			—			(240	)		—
Proceeds from letter of credit facility deposited with trustee		(1,250	)		—			—			—
Costs to remove retired property		(9	)		(25	)		(40	)		(44	)
Investment in unconsolidated affiliate		—			—			(15	)		—
Other		2			(2	)		(7	)		48
Cash used in investing activities from continuing operations		(34,563	)		(2,283	)		(2,664	)		(1,038	)
Discontinued operations:
Cash provided by (used in) operating activities		(7	)		35			30			(265	)
Cash used in financing activities		—			—			—			—
Cash provided by (used in) investing activities		—			—			—			4
Cash provided by (used in) discontinued operations		(7	)		35			30			(261	)
Net change in cash and cash equivalents		(1,155	)		1,411			(12	)		(69	)
Cash and cash equivalents — beginning balance		1,436			25			37			106
Cash and cash equivalents — ending balance	$	281		$	1,436		$	25		$	37

See Notes to Financial Statements.

105

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

	Successor		Predecessor
	December 31, 2007		December 31, 2006
ASSETS
Current assets:
Cash and cash equivalents	$	281	$	25
Restricted cash		56		58
Trade accounts receivable — net (Note 16)		1,099		959
Income taxes receivable		101		—
Inventories		405		383
Commodity and other derivative contractual assets (Note 20)		280		950
Accumulated deferred income taxes (Note 14)		9		253
Margin deposits related to commodity positions		513		7
Unamortized debt issuance costs and other current assets		376		177
Total current assets		3,120		2,812
Restricted cash		1,296		258
Investments		868		712
Property, plant and equipment — net		28,650		18,569
Goodwill (Note 3)		22,954		542
Intangible assets — net (Note 3)		4,365		187
Regulatory assets — net		1,305		2,028
Commodity and other derivative contractual assets (Note 20)		73		345
Other noncurrent assets		1,130		380
Assets held for sale		23		—
Total assets	$	63,784	$	25,833
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings (Note 17)	$	1,718	$	1,491
Long-term debt due currently (Note 17)		513		485
Trade accounts payable		904		1,093
Commodity and other derivative contractual liabilities (Note 20)		297		293
Margin deposits related to commodity positions		5		681
Other current liabilities		1,416		1,040
Total current liabilities		4,853		5,083
Accumulated deferred income taxes (Note 14)		6,664		4,238
Investment tax credits		47		363
Commodity and other derivative contractual liabilities (Note 20)		2,282		191
Long-term debt, less amounts due currently (Note 17)		38,603		10,631
Other noncurrent liabilities and deferred credits		4,650		3,187
Total liabilities		57,099		23,693
Commitments and Contingencies (Note 18)
Shareholders’ equity (Note 19)		6,685		2,140
Total liabilities and shareholders’ equity	$	63,784	$	25,833

See Notes to Financial Statements.

106

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED SHAREHOLDERS’ EQUITY

(Millions of Dollars)

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007
							Year Ended December 31,
							2006			2005
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		$	2
Effect of two-for-one stock split		—			—			—			3
Balance at end of period (number of shares outstanding:
Successor: 2007 — 1,664,345,953;
Predecessor: October 10, 2007 — 461,152,009; 2006 — 459,244,523; and 2005 — 470,845,978)		—			5			5			5
Additional paid-in capital:
Balance at beginning of period		—			1,104			1,840			2,806
Investment by Sponsor Group and other investors		8,279			—			—			—
Common stock repurchases		—			(13	)		(1,012	)		(1,092	)
Discount (premium) on repurchase of equity-linked debt securities (related to equity component) and reversal of contract adjustment payment liability		—			—			—			(13	)
Effects of stock-based incentive compensation plans		—			(66	)		27			33
Excess tax benefit on stock-based compensation		—			82			41			28
Issuance of shares under equity-linked debt securities		—			—			180			75
Cost of Thrift Plan shares released by LESOP trustee (Note 22)		—			210			2			1
Effects of executive deferred compensation plan		—			11			13			—
Effect of two-for-one stock split		—			—			—			(3	)
Other		—			(2	)		13			5
Balance at end of period		8,279			1,326			1,104			1,840
Retained earnings (deficit):
Balance at beginning of period		—			622			(1,168	)		(2,283	)
Net income (loss)		(1,360	)		723			2,552			1,722
Dividends declared on common stock ($-, $1.30, $1.67 and $1.26 per share)		—			(596	)		(768	)		(598	)
Dividends on preference stock ($0, $0, $0 and $3,278 per share)		—			—			—			(10	)
Effect of adoption of FIN 48		—			33			—			—
LESOP dividend deduction tax benefit and other		—			3			6			1
Balance at end of period		(1,360	)		785			622			(1,168	)
Accumulated other comprehensive gain (loss), net of tax effects:
Pension and other postretirement employee benefit liability adjustments:
Balance at beginning of period		—			(2	)		(60	)		(14	)
Reclassification of pension and other retirement benefit costs		(57	)		49
Change in minimum pension liability		—			—			71			(46	)
SFAS 158 transition adjustment		—			—			(13	)		—
Balance at end of period		(57	)		47			(2	)		(60	)
Amounts related to cash flow hedges:
Balance at beginning of period		—			411			(142	)		(172	)
Change during the period		(177	)		(377	)		553			30
Balance at end of period		(177	)		34			411			(142	)
Total accumulated other comprehensive gain (loss) at end of period		(234	)		81			409			(202	)
Total common stock equity at end of period		6,685			2,197			2,140			475
Preference stock:
Balance at beginning of period		—			—			—			300
Preference stock redemption		—			—			—			(300	)
Balance at end of period		—			—			—			—
Shareholders’ equity at end of period	$	6,685		$	2,197		$	2,140		$	475

See Notes to Financial Statements.

107

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    SIGNIFICANT ACCOUNTING POLICIES

Description of Business

EFH Corp. (formerly TXU Corp., the Predecessor), 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 Luminant, which is engaged in electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases, and commodity risk management and trading activities, and TXU Energy, which is engaged in 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, and the outstanding shares of common stock of EFH Corp. were converted into the right to receive $69.25 per share.

The aggregate purchase price paid for the equity securities of EFH Corp. was $31.9 billion, which was funded by equity financing from the Sponsor Group and certain other investors and by debt financings. These debt financings also funded the repayment and redemption of borrowings under existing credit facilities and other financing arrangements. The purchase price is exclusive of costs directly associated with the Merger, consisting of legal, consulting and other professional service fees incurred by the Sponsor Group. See Note 2 for discussion of the Merger, Note 17 for further discussion regarding debt financing and Note 10 for further discussion of the regulatory settlement.

As part of the Merger, to enhance the separateness of Oncor from the other EFH Corp. businesses, various legal, financial and contractual “ring-fencing” actions were taken. Such measures include, among other things: TXU Electric Delivery Company’s name change to Oncor Electric Delivery Company; 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 named “Oncor Electric Delivery Company LLC”; 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, including TXU Energy and the Luminant entities, 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.

In connection with the Merger, certain wholly-owned subsidiaries of EFH Corp. established for the purpose of developing and constructing new generation facilities (formerly referred to as TXU DevCo) have become subsidiaries of TCEH, and certain assets and liabilities of other of these subsidiaries that did not become subsidiaries of TCEH were transferred to TCEH and its subsidiaries. Those subsidiaries holding impaired construction work-in-process assets related to eight canceled coal-fueled generation units (see Note 7) have not become subsidiaries of TCEH. In addition, a wholly-owned subsidiary of EFC Holdings representing a lease trust holding certain combustion turbines has become a subsidiary of TCEH.

108

EFH Corp. has two reportable segments: the Competitive Electric segment (formerly the TXU Energy Holdings segment), which includes the activities of TCEH as well as equipment salvage and resale activities related to the canceled development of new generation facilities, and the Regulated Delivery segment (formerly the Oncor Electric Delivery segment), which includes the activities of Oncor, its wholly-owned bankruptcy-remote financing subsidiary and certain revenues and costs associated with installation of equipment for a third party that will facilitate Oncor’s technology initiatives. See Note 27 for further information concerning reportable business segments.

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) and cash flows present results of operations and cash flows of EFH Corp. for periods preceding the Merger (Predecessor) and of EFH Corp. for periods subsequent to the Merger (Successor). The consolidated financial statements of the Predecessor have been prepared on the same basis as the audited financial statements included in EFH Corp.’s 2006 Form 10-K/A with the exception of the adoption of FIN 48 and changes in accounting policies as discussed below. The consolidated financial statements of the Successor reflect the application of purchase accounting, 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.

Discontinued Businesses

Note 4 presents detailed information regarding the effects of discontinued businesses, the results of which have been classified as discontinued operations.

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.

109

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 commodity-related derivative instruments under mark-to-market accounting are reported in the balance sheet as commodity contract 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. Under the exception criteria of SFAS 133, EFH Corp. may elect the “normal” purchase and sale exemption. A 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. Changes in value of fair value hedges are recorded as derivative assets or liabilities with an offset to net income, and the carrying value of the related asset or liability (hedged item) is adjusted for changes in fair value with an offset to net income. If the fair value hedge is settled prior to the maturity of the hedged item, the cumulative fair value gain or loss associated with the hedge is amortized into income over the remaining life of the hedged item. In the statement of cash flow, the effects of settlements of derivative instruments are classified consistent with the related hedged transactions.

To qualify for hedge accounting, a hedge must be considered highly effective in offsetting changes in fair value of the hedged item. Assessment of the hedge’s effectiveness is tested at least quarterly throughout its term to continue to qualify for hedge accounting. Changes in fair value that represent hedge ineffectiveness, even if the hedge continues to be assessed as effective, are immediately recognized in net income. Ineffectiveness is generally measured as the cumulative excess, if any, of the change in value of the hedging instrument over the change in value of the hedged item. See Notes 17 and 20 for additional information concerning hedging activity.

Commodity contract and derivative assets and liabilities and margin deposits reported in the consolidated balance sheet each reflect counterparty netting in accordance with legal right of offset agreements.

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).

110

Under a realignment of the wholesale energy operations effective January 1, 2006, management of wholesale purchases and sales of electricity for purposes of balancing electricity supply and demand was segregated from the buying and selling of electricity for trading purposes. Previously, all wholesale electricity purchases and sales were managed in aggregate under a “portfolio management” structure, as the primary activity was energy balancing, and all wholesale activity utilized (and continues to utilize) contracts for physical delivery. Financial derivative instruments, as are common in natural gas markets, are not as readily available in the ERCOT electricity market. The realignment reflects an expectation of a growing market for electricity trading in Texas. Under the previous structure, all purchases and sales scheduled with ERCOT for delivery were reported gross in the income statement, and “booked-out” sales and purchases (agreement with the counterparty to net settle offsetting volumes of purchases and sales before scheduling for delivery) were reported net. Effective with the January 1, 2006 realignment, those contracts that are separately managed as a trading book and scheduled for physical delivery are reported net upon settlement in accordance with EITF 02-3. All transactions reported net, including booked-out contracts, are reported as a component of revenues. Gross revenues from electricity trading activities totaled $334 million in the period from October 11, 2007 through December 31, 2007, $1.1 billion from January 1, 2007 through October 10, 2007 and $1.3 billion in 2006.

In addition, EFH Corp. revised its reporting of ERCOT electricity balancing transactions effective with 2006 reporting. These transactions 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. EFH Corp. had historically reported the net amount as a component of purchased power cost as the activity consistently represented a net purchase of electricity prior to 2005 due in part to EFH Corp.’s retail load exceeding generation volumes. 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. Accordingly, net electricity balancing transactions are reported in revenues and the 2005 amounts have been reclassified to revenues for comparative purposes. The amount reported in revenues totaled $9 million in net purchases in the period from October 11, 2007 through December 31, 2007, $14 million in net purchases in the period from January 1, 2007 through October 10, 2007, $31 million in net purchases in 2006 and $225 million in net sales in 2005.

Realized and unrealized gains and losses from transacting in energy-related derivative instruments are reported as a component of revenues. See discussion above under “Derivative Instruments and Mark-to-Market Accounting.”

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 8 for details of the impairment of the natural gas-fueled generation plants recorded in the second quarter of 2006.

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 No. 142, “Goodwill and Other Intangible Assets”. The impairment tests performed are based on discounted cash flow analyses. No impairment has been recognized as of December 31, 2007 for goodwill or intangible assets with indefinite lives. See Note 3 for details of goodwill and intangible assets with indefinite lives.

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.

111

Amortization of Nuclear Fuel

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

Major Maintenance

Major maintenance costs incurred during generation plant outages and the costs of other maintenance activities are charged to expense as incurred. 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, as required. See Note 22 for details with respect to the adoption of this standard and other 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 have been granted under the plan and 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.

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. 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 competitive operations 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.

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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 below under “Changes in Accounting Standards” and in Note 12.

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 18 for a discussion of contingencies.

Cash Equivalents

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

Restricted Cash

The terms of certain agreements require the restriction of cash for specific purposes. At December 31, 2007, $1.250 billion of cash is restricted to support letters of credit. See Note 17 and 28 for more details regarding restricted cash.

Property, Plant and Equipment

At December 31, 2006, properties are stated at original cost. As a result of purchase accounting, unregulated property amounts at October 10, 2007 were adjusted to estimated fair values while subsequent additions will be recorded at cost. Regulated properties at Oncor continue to be reported at original cost, which is considered to be fair value due to the 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 life.

Capitalized Interest and Allowance for Funds Used During Construction (AFUDC)

Interest related to TCEH’s 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. See Notes 15 and 28 for details of amounts.

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.

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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 carrying values of these intangible assets at December 31, 2007 reflect 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. 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.

Investments

Investments in a nuclear decommissioning trust fund are carried at fair 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 21 for details of investments.

Changes in Accounting Standards

In September 2006, the FASB issued SFAS 157, “Fair Value Measurements” 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. SFAS 157 does not require any new fair value measurements. Although the statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, it may be adopted early. On October 11, 2007, effective with the closing of the Merger, EFH Corp. early-adopted SFAS 157 for assets and liabilities recorded at fair value on a recurring basis. The adoption of SFAS 157 also reflects the application of FSP 157-2, “Effective Date of FASB Statement No. 157”, which was issued by the FASB in February 2008 and delays until financial statements issued after December 15, 2008 the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). See Note 24 for related disclosures.

Effective January 1, 2007, EFH Corp. adopted FIN 48 as required. FIN 48 provides clarification of SFAS 109 with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. The adoption also reflects the application of FSP FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48”, which provides guidance on how to determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. See Note 12 for the impacts of adopting FIN 48 and required disclosures.

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115”, which permits an entity to choose to measure certain financial assets and liabilities at fair value. SFAS 159 also revises provisions of SFAS 115 that apply to available-for-sale and trading securities. This statement is effective for fiscal years beginning after November 15, 2007. EFH Corp. does not expect SFAS 159 to materially impact its financial statements.

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In April 2007, the FASB issued FASB Staff Position 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 contractual fair value amounts and related disclosures. This FSP is effective for fiscal years beginning after November 15, 2007. EFH Corp. is evaluating the impact of this standard on its balance sheet.

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations”. SFAS 141R will significantly change the accounting for business combinations and applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Earlier adoption is prohibited, so the new rule has not impacted purchase accounting related to the Merger. EFH Corp. is evaluating whether certain aspects of SFAS 141R could impact the accounting for the Merger in future periods.

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. While EFH Corp. has announced its intention to sell up to 20% of its interest in Oncor, neither Oncor nor EFH Corp. currently has any material noncontrolling interests.

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. EFH Corp. is evaluating the impact of this statement on its financial statement disclosures.

2.    FINANCIAL STATEMENT EFFECTS OF THE MERGER

As discussed in Note 1, the Merger was completed on October 10, 2007 and 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 17 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 17)		27.0	Transaction costs (c)		0.8
EFH Corp. senior unsecured interim facility (Note17)		4.5	Repayment of existing debt (Note 17)		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.

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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 totaled $23.0 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.

The purchase price allocation at December 31, 2007 is substantially complete; however, additional analysis with respect to the value of certain assets, contractual arrangements, contingent liabilities and debt could result in a change in the total amount of goodwill and amounts assigned to EFH Corp.’s reporting units.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed:

Equity purchase price		$	31,935
Transaction costs			759
Total purchase price			32,694
Property, plant and equipment	28,399
Intangible assets	4,485
Regulatory assets and deferred debits	1,447
Other assets	5,359
Total assets acquired	39,690
Short-term borrowings and long-term debt	14,183
Deferred tax liabilities	7,969
Other liabilities	7,798
Total liabilities assumed	29,950
Net identifiable assets acquired			9,740
Goodwill		$	22,954

Exit liabilities recorded as part of the purchase price allocation totaled approximately $60 million, which includes amounts related to the cancellation of the development of coal-fueled generation facilities discussed in Note 7 and the exit of certain administrative activities. The substantial majority of the liability was not settled as of December 31, 2007.

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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, 2006. The unaudited pro forma information is provided for informational purposes only and is not necessarily indicative of what EFH Corp.’s financial position or results of operations would have been if the transactions had occurred on that date, or what EFH Corp.’s financial position or results of operations will be for any future periods.

	2007			2006
	(millions of dollars)
Revenues	$	7,999		$	10,865
Net income (loss)		(2,315	)		363

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 $903 million income tax benefit. Pro forma adjustments for the year ended December 31, 2006 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.

3.    GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

Goodwill as of December 31, 2007 totaled $23.0 billion with $18.1 billion assigned to the Competitive Electric segment and $4.9 billion to the Regulated Delivery segment.

As discussed in Note 2, EFH Corp. accounted for the Merger under purchase accounting. The 2007 amount above represents the excess of the purchase price over the fair value of the tangible and identifiable intangible net assets acquired in the Merger. 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 and the Regulated Delivery segment were based on the relative enterprise values of those businesses at the closing date of the Merger. See Note 2 for details of the purchase price allocation.

EFH Corp. evaluates goodwill for impairment at least annually (as of October 1) in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets”. The impairment tests performed are based on discounted cash flow analyses. No goodwill impairment was recognized in 2007.

At December 31, 2006, goodwill (net of accumulated amortization) totaled $542 million with $517 million assigned to TCEH and $25 million to Oncor. These goodwill amounts were eliminated as a result of the Merger.

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Identifiable Intangible Assets

Identifiable intangible assets are comprised of the following:

	Successor						Predecessor
	As of December 31, 2007						As of December 31, 2006
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	79	$	384	$	—	$	—	$	—
Favorable purchase and sales contracts		702		68		634		—		—		—
Capitalized in-service software		225		71		154		423		350		73
Emissions and renewable energy credits		1,525		19		1,506		—		—		—
Land easements		179		67		112		178		64		114
Total intangible assets subject to amortization	$	3,094	$	304		2,790	$	601	$	414		187
Trade name (not subject to amortization)						1,436						—
Mineral interests (not currently subject to amortization)						139						—
Total intangible assets					$	4,365					$	187

Amortization expense related to intangible assets consisted of:

	Successor			Predecessor
	Useful lives at December 31, 2007 (weighted average in	Period from October 11, 2007 through December 31,		Period From January 1, 2007 through October 10,		Year Ended December 31,
	years)	2007		2007		2006		2005
Retail customer relationship	4	$	79	$	—	$	—	$	—
Favorable purchase and sales contracts	11		72		—		—		—
Capitalized in-service software	7		8		23		35		20
Emission and renewable energy credits	23		20		—		—		—
Land easements	69		—		2		2		2
Total amortization expense		$	179	$	25	$	37	$	22

Because of the immateriality of the amounts, capitalized in-service software and land easements were reported as part of property, plant and equipment in the balance sheet in previous reporting periods.

As discussed in Note 2, EFH Corp. accounted for the Merger under purchase accounting and identified the following separately identifiable and previously unrecognized intangible assets acquired:

• Retail Customer Relationship— Retail customer relationship intangible asset represents the value of TXU Energy’s 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 retail customer relationship intangibles asset is reported as part of depreciation and amortization expense in the income statement.

• Favorable Purchase and Sales Contracts— Favorable purchase and sales contracts intangible asset primarily represents the in-the-money value of commodity contracts for which: 1) TCEH 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. 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 value of the TXU Energy trade name, and as an indefinite-lived asset is not subject to amortization. This intangible asset will be evaluated for impairment at least annually (as of October 1) in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets”.

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• Emission Allowances and Credits –This intangible asset represents the fair value of emissions credits granted to or purchased by EFH Corp. 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.

Estimated Amortization of Intangible Assets—The estimated aggregate amortization expense of intangible assets for each of the five succeeding fiscal years from December 31, 2007 is as follows:

Year	Successor
2008	$	392
2009		481
2010		283
2011		248
2012		183

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. (Also see discussion in Note 18 under “Income Tax Contingencies.”)

In January 2005, EFH Corp. executed a comprehensive settlement agreement resolving potential claims relating to TXU Europe. The $222 million settlement was paid in full in October 2005. As discussed above, credits representing insurance recoveries related to the settlement were recorded in 2006 and 2007.

The table below reflects the results of the various businesses reported as discontinued operations in 2005:

	TXU Gas		TXU Australia		Strategic Retail Services			Pedrick- town			Total
2005
Operating revenues	$	—	$	—	$	—		$	12		$	12
Operating costs and expenses		—		—		—			14			14
Other deductions — net		—		—		3			—			3
Operating loss before income taxes		—		—		(3	)		(2	)		(5	)
Income tax benefit		—		—		(1	)		—			(1	)
Credits (charges) related to exit (after-tax)		3		10		—			(4	)		9
Income (loss) from discontinued operations	$	3	$	10	$	(2	)	$	(6	)	$	5

TXU Gas

In October 2004, Atmos Energy Corporation and TXU Gas completed a merger by division, which resulted in the disposition of the operations of TXU Gas for $1.9 billion in cash (the TXU Gas transaction). TXU Gas was largely a regulated business engaged in the purchase, transmission, distribution and retail sale of natural gas. A net credit of $3 million in 2005 includes a $7 million after-tax benefit from a favorable resolution of a working capital adjustment related to the disposition and a $9 million charge primarily representing an adjustment to the estimated tax effect of the disposition. As discussed above, an income tax benefit related to TXU Gas was recorded in 2006.

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TXU Australia

In July 2004, EFH Corp. completed the sale of TXU Australia to Singapore Power Ltd. for $1.9 billion in cash and $1.7 billion of assumed debt. TXU Australia’s operations consisted of a portfolio of competitive and regulated energy businesses, principally in Victoria and South Australia. The $10 million credit recorded in 2005 primarily represented an adjustment to the estimated income tax effect of the sale.

Strategic Retail Services

In December 2003, TCEH finalized a formal plan to sell its strategic retail services business, which was engaged principally in providing energy management services. Results in 2005 reflect an after-tax charge of $2 million related to a litigation settlement.

Pedricktown

In the second quarter of 2004, TCEH initiated a plan to sell the Pedricktown, New Jersey 122 MW electricity generation business. The business was sold in July 2005 for $8.7 million in cash. A $4 million after-tax charge in 2005 represents a working capital adjustment related to the sale transaction.

5.    EXTRAORDINARY ITEM

In December 2005, a subsidiary of EFH Corp. entered into an agreement to purchase, for $69 million in cash, the owner participant interest in a trust established to lease combustion turbines to another subsidiary of EFH Corp. The trust is a variable interest entity, and in accordance with FIN 46R, the trust was consolidated at December 31, 2005, with the trust’s combustion turbine assets and related debt recorded at estimated fair values of $35 million and $96 million, respectively. The transaction was closed in March 2006. In the fourth quarter of 2005, EFH Corp. recorded an extraordinary loss of $50 million (net of a $28 million tax benefit) for the excess of the purchase price over the fair value of the trust’s net assets, net of the reversal of a previously established liability of $59 million related to the combustion turbine lease. Classification of the loss as extraordinary is in accordance with the provisions of FIN 46R.

6.    CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES

FIN 47 was effective with reporting for the fourth quarter of 2005. This interpretation clarifies the term “conditional asset retirement” under SFAS 143 and requires entities to record the fair value of legally binding asset retirement obligations, the timing or method of settlement of which is conditional on a future event. For EFH Corp., such liability relates to generation assets asbestos removal and disposal costs. As the new accounting rule required retrospective application to the inception of the liability, the effects of the adoption reflect the accretion and depreciation from the liability inception date through December 31, 2005. The liability is accreted each period, representing the time value of money, and the capitalized cost is depreciated over the remaining useful life of the related asset.

The following table details the $8 million net charge in December 2005 arising from the adoption of FIN 47:

Increase in property, plant and equipment — net	$	5
Increase in other noncurrent liabilities and deferred credits		(17	)
Increase in accumulated deferred income taxes		4
Cumulative effect of change in accounting principle	$	(8	)

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7.    CHARGES RELATED TO CANCELED 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, the substantial majority of which was recorded in the first quarter, 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.

The construction work-in-process asset balances totaled $871 million at March 31, 2007 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, 2007 totaled $112 million and consisted of estimated recovery amounts, using a probability-weighted methodology, from equipment salvage and potential resale activities.

Subsidiaries of EFH Corp. have terminated all of the equipment orders, with the exception of one in-process boiler expected to be resold, and air permit applications 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.

8.    IMPAIRMENT OF NATURAL GAS-FUELED GENERATION UNITS

In 2006, EFH Corp. performed an evaluation of its natural gas-fueled generation units for impairment in accordance with the requirements of SFAS 144, which provides that long-lived assets should be tested for recovery whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. 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 gas-fueled generation units, which have generally been operated to meet peak demands for electricity, would be sold or otherwise disposed of before the end of their previously estimated useful lives and should be tested for impairment as an asset group. 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. Because of the highly judgmental nature of key assumptions and potential volatility of market conditions, the adjusted carrying value of the units did not necessarily represent the amount of proceeds from any potential transaction to sell the units. The impairment was reported in other deductions in the Statements of Consolidated Income and included in the results of the Competitive Electric segment.

9.    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 price-to-beat 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 pretax 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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10.    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 a final order approving the stipulation.

In addition to commitments Oncor made in its filings in the PUCT review, the stipulation includes the following provisions, among others:

• Oncor will provide a one-time $72 million credit to its REP customers. While the credit will be provided to REPs, the intent of the parties to the agreement is that the credit will be passed through to end-use retail consumers, and only those REPs that agree to do so will receive their portion of the credit. The credit will be provided in the summer of 2008, and this amount has been recorded as a regulatory liability as part of purchase accounting and consistent with SFAS 71.

• Consistent with the 2006 cities rate settlement, Oncor will file a system-wide rate case no later than July 1, 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 has been recorded as a regulatory liability as part of purchase accounting and consistent with SFAS 71.

• If two or more of the rating agencies lower Oncor’s credit ratings below investment grade, 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.

11.    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), unless the Cities and Oncor mutually agree that such a filing is unnecessary. Oncor extended the benefits of the agreement to 292 nonlitigant cities. Based on the final agreements, including the participation of the nonlitigant cities, payments to the cities are estimated to total approximately $70 million, including incremental franchise taxes.

This amount is being recognized in earnings of the Regulated Delivery segment over the period from May 2006 through June 2008. Amounts recognized totaled $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, and are reported in other deductions (see Note 12) and franchise and revenue-based taxes in the Statements of Consolidated Income (Loss).

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12.    ADOPTION OF NEW INCOME TAX ACCOUNTING RULES (FIN 48)

FIN 48 requires that each tax position 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 quarter ended March 31, 2007 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, 1997, with few exceptions, are complete. Texas franchise tax return periods under examination or still open for examination range from 2002 to 2006.

The IRS completed its examination of EFH Corp.’s US income tax returns for the years 1997 through 2002, and proposed adjustments were received in July 2007. EFH Corp. filed an appeal of the proposed adjustments in the third quarter of 2007. The proposed adjustments received from the IRS with respect to the 1997-2002 income tax returns do not materially affect EFH Corp.’s assessment of uncertain tax positions as reflected in the amounts recorded upon adoption of FIN 48.

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 $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 $105 million in accrued interest at December 31, 2007. (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 year ended December 31, 2007:

Balance at January 1, 2007, excluding interest and penalties	$	1,770
Additions based on tax positions related to prior years		97
Reductions based on tax positions related to prior years		(124	)
Additions based on tax positions related to the current year		101
Settlements with taxing authorities		(10	)
Reductions related to the lapse of the tax statute of limitations		—
Balance at December 31, 2007, excluding interest and penalties	$	1,834

Of the balance at December 31, 2007, $1.7 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 $55 million, resulting in increased income from continuing operations and a favorable impact on the effective tax rate.

EFH Corp. does not expect that the total amount of liabilities recorded related to uncertain tax positions assessed as of the date of the adoption will significantly increase or decrease within the next 12 months. To the extent any uncertain tax positions related to permanent items are resolved prior to January 1, 2009, the effects would be recorded to goodwill and not in the income statement in accordance with SFAS 141. Upon adoption of SFAS 141R on January 1, 2009, resolution of permanent items will be recorded in the income statement and affect the effective tax rate.

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13.    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 effective date of the Texas margin tax for EFH Corp. is January 1, 2008. The computation of tax liability will be based on 2007 revenues as reduced by certain deductions and was accrued in 2007.

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.

14.    INCOME TAXES

The components of EFH Corp.’s income tax expense applicable to continuing operations are as follows:

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31,
							2006			2005
Current:
US Federal	$	52		$	400		$	500		$	145
State		10			20			5			6
Non-US		—			—			1			—
Total		62			420			506			151
Deferred:
US Federal		(722	)		12			715			498
State		(12	)		(108	)		63			4
Total		(734	)		(96	)		778			502
Amortization of investment tax credits		(1	)		(15	)		(21	)		(21	)
Total	$	(673	)	$	309		$	1,263		$	632

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

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31,
							2006			2005
Income from continuing operations before income taxes, extraordinary gain (loss) and cumulative effect of changes in accounting principles:
Domestic	$	(2,034	)	$	1,008		$	3,728		$	2,408
Non-US		—			—			—			(1	)
Total	$	(2,034	)	$	1,008		$	3,728		$	2,407
Income taxes at the US federal statutory rate of 35%	$	(712	)	$	353		$	1,305		$	842
Lignite depletion allowance		(5	)		(30	)		(51	)		(33	)
Production activities deduction		10			(10	)		(14	)		—
Recognition of benefits related to TXU Europe		—			—			—			(138	)
Amortization of investment tax credits — net of deferred income tax effect		(1	)		(12	)		(15	)		(15	)
Amortization (under regulatory accounting) of statutory rate changes		—			2			(7	)		(7	)
Medicare subsidy — other postretirement employee benefits		(2	)		(6	)		(8	)		(9	)
Nondeductible compensation expense		—			—			—			(5	)
State income taxes, net of federal tax benefit		(3	)		16			6			7
Texas margin tax — deferred tax adjustments (Note 13)		—			(70	)		44			—
Nondeductible merger transaction costs		23			—			—			—
Deferred tax adjustments		—			25			—			—
Accrual of interest		12			43			9			—
Other, including audit settlements		5			(2	)		(6	)		(10	)
Income tax expense	$	(673	)	$	309		$	1,263		$	632
Effective tax rate		33.1	%		30.7	%		33.9	%		26.3	%

TXU Europe

In 2005, EFH Corp. recognized a $138 million tax benefit related to the 2002 TXU Europe worthlessness deduction. The recognition of the tax benefit was based on the identification of tax planning strategies EFH Corp. would implement to ensure utilization of capital losses associated with the write-off of the investment in TXU Europe. Classification of this benefit in continuing operations is in accordance with SFAS 109.

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Deferred Income Tax Balances

Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2007 and 2006, balance sheet dates are as follows:

	Successor							Predecessor
	December 31, 2007							December 31, 2006
	Total		Current			Noncurrent		Total		Current			Noncurrent
Deferred Income Tax Assets
Alternative minimum tax credit carryforwards	$	789	$	—		$	789	$	768	$	209		$	559
Employee benefit liabilities		456		29			427		496		7			489
Unamortized investment tax credits		—		—			—		109		—			109
Net operating loss (NOL) carryforwards		194		—			194		12		—			12
Regulatory liabilities		111		—			111		43		—			43
Identifiable intangible liabilities		269		—			269		—		—			—
Capital loss carryforward		—		—			—		31		31			—
Deferred gain on sale of assets		—		—			—		95		—			95
Other		133		11			122		110		12			98
Total		1,952		40			1,912		1,664		259			1,405
Deferred Income Tax Liabilities
Property, plant and equipment		5,787		—			5,787		3,275		—			3,275
Commodity contracts (mark-to-market)		224		31			193		966		4			962
Deductions related to TXU Europe		—		—			—		465		—			465
Regulatory assets		680		—			680		837		—			837
Identifiable intangible assets		1,580		—			1,580		72		—			72
Debt fair value discounts		301		—			301		—		—			—
Other		35		—			35		34		2			32
Total		8,607		31			8,576		5,649		6			5,643
Net Deferred Income Tax (Asset) Liability	$	6,655	$	(9	)	$	6,664	$	3,985	$	(253	)	$	4,238

At December 31, 2007, EFH Corp. had $789 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, 2007, EFH Corp. had net operating loss (NOL) carryforwards for federal income tax purposes of $553 million that expire between 2023 and 2027. 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 income tax effects of the components included in accumulated other comprehensive income at December 31, 2007 and 2006 totaled a net deferred tax asset of $91 million and a net deferred tax liability of $212 million, respectively.

See Note 12 for discussion regarding the implementation of FIN 48, which addresses accounting for uncertain tax positions.

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15.    OTHER INCOME AND DEDUCTIONS

	Successor			Predecessor
	Period from October 11, 2007 through December 31,			Period From January 1, 2007 through October 10,			Year Ended December 31,
	2007			2007			2006			2005
Other income:
Gain on contract settlement (a)	$	—		$	—		$	26		$	—
Amortization of gain on sale of TXU Fuel (b)		—			36			47			47
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting (see Note 28)		10			—			—			—
Net gain on sale of other properties and investments (c)		1			4			22			42
Insurance recovery of litigation settlement (d)		—			—			15			35
Reduction of insurance reserves unrelated to ongoing operations		1			7			—			—
Settlement penalty for coal tonnage delivery deficiency		—			6			—			—
Royalty income from lignite and natural gas leases		1			8			—			—
Insurance recoveries related to generation assets		—			—			2			8
Electricity sale agreement termination fee		—			—			—			4
Equity portion of allowance for funds used during construction		—			—			—			3
Other		1			8			9			12
Total other income	$	14		$	69		$	121		$	151
Other deductions:
Net charges related to canceled development of generation facilities (Note 7)	$	2		$	755		$	—		$	—
Charge related to termination of rail car lease (e)		—			10			—			—
Writeoff of deferred transaction costs (f)		—			30			—			—
Professional fees incurred related to the Merger		51			39			—			—
Charge for impairment of natural gas-fueled generation plants (Note 8)		—			—			198			—
Asset writedown and generation-related lease termination and impairment charges (credit) (g)		—			(48	)		4			(16	)
Equity losses — unconsolidated affiliates		—			1			14			—
Litigation settlements		—			—			9			7
Costs related to cities rate settlement (Note 11)		6			20			13			1
Charge for settlement of a retail matter with the PUCT		—			5			—			—
Capgemini outsourcing transition costs		—			—			—			11
Expenses related to InfrastruX Energy Services joint venture (h)		—			12			7			—
Ongoing pension and other postretirement benefit costs related to discontinued businesses		(2	)		7			23			15
Charge (credit) related to coal contract counterparty claim (i)		—			—			(12	)		12
Other		4			10			13			15
Total other deductions	$	61		$	841		$	269		$	45

(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 nonsegment results).

(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 the Competitive Electric segment).

(c) Includes gains on land sales of $1 million in the period from October 11, 2007 to December 31, 2007, $4 million in the

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period from January 1, 2007 to October 10, 2007, $12 million in 2006 and $33 million in 2005 (all reported in the Competitive Electric segment except $1 million in the October 11, 2007 to December 31, 2007 period, $2 million in the January 1, 2007 to October 10, 2007 period and $1 million in 2006 reported in the Regulated Delivery segment). The 2006 period also includes a $10 million gain related to the sale of mineral interests (reported in Corporate and Other nonsegment operations). The 2005 period also includes a $7 million gain on the sale of an out-of-state electricity transmission project (reported in the Competitive Electric segment).

(d) Represents additional insurance recoveries recorded in 2006 and 2005 related to the 2005 settlement of the shareholders’ litigation (reported in Corporate and Other nonsegment operations).

(e) Represents costs associated with termination and refinancing of a rail car lease (reported in the Competitive Electric segment).

(f) Represents 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 are no longer expected to be consummated as a result of the Merger (reported in Corporate and Other nonsegment results).

(g) In 2004, EFH Corp. recorded a liability of $157 million for leases of certain natural gas-fueled combustion turbines, net of estimated sublease revenues that are no longer operated for its own benefit. A $16 million credit was recorded in 2005 to adjust the liability for changes in estimated sublease proceeds, and in the third quarter of 2007, a $48 million reduction in the 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.

(h) Consists of previously deferred costs, consisting primarily of professional fees that were written-off due to suspension of the agreement. Of these amounts, $8 million was reported in the Corporate and Other nonsegment results and the balance was reported in the Regulated Delivery segment results.

(i) In 2006, EFH Corp. recorded income of $12 million upon the settlement of a claim against a counterparty for nonperformance under a coal contract. A charge in the same amount was recorded in 2005 for losses due to the nonperformance (reported in the Competitive Electric segment results).

16.    TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

Sale of Receivables

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 (the funding entities).

In connection with the Merger, the accounts receivable securitization program was amended. Certain financial tests relating to TCEH and the originators that could have affected the amount of available funding under the program or caused a termination event or a default, including TCEH’s debt to capital (leverage) and fixed charge coverage ratios, were deleted and replaced with other tests. As amended, among other things, the amount of customer deposits held by the originators can reduce funding available under the program so long as TCEH’s long term senior unsecured debt rating is lower than investment grade. Also, the originators will continue to be eligible to participate in the program so long as TCEH provides the required form of parent guaranty. 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. Subsequent to the Merger, only subsidiaries of TCEH participate in the accounts receivable securitization program.

The maximum amount currently available under the accounts receivable securitization program is $700 million, and the program funding was $363 million as of December 31, 2007. Under certain circumstances, 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. Funding availability for all originators is 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 $116 million, reduced funding availability as of December 31, 2007 as TCEH’s credit ratings were lower than Ba3/BB-.

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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 as well as 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 $296 million and $211 million at December 31, 2007 and 2006, respectively.

The discount from face amount on the purchase of receivables principally funds program fees paid by TXU Receivables Company to the funding entities. The discount also funds a servicing fee paid by TXU Receivables Company to EFH Corporate Services Company, a direct subsidiary of EFH Corp. The program fees, also referred to as losses on sale of the receivables under SFAS 140, consist primarily of interest costs on the underlying financing. The servicing fee compensates EFH Corporate Services Company for the collection agent services being performed, including the maintenance of detailed accounts receivable collection records. 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
	Period from October 11, 2007 through			Period From January 1, 2007 through			Year Ended December 31,
	December 31, 2007			October 10, 2007			2006			2005
Program fees	$	9		$	32		$	40		$	23
Program fees as a percentage of average funding (annualized)		9.5	%		6.4	%		5.8	%		4.0	%
Servicing fees		1			3			4			4

The accounts receivable balance reported in the December 31, 2007 consolidated balance sheet includes $659 million face amount of trade accounts receivable of TCEH subsidiaries sold to TXU Receivables Company, such amount having been reduced by $363 million of undivided interests sold by TXU Receivables Company. Funding under the program decreased $264 million in 2007, decreased $44 million in 2006 and increased $197 million in 2005. 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
	Period from October 11, 2007 through			Period From January 1, 2007 through October 10, 2007			Year Ended December 31,
	December 31, 2007						2006			2005
Cash collections on accounts receivable	$	1,538		$	6,251		$	8,503		$	7,450
Face amount of new receivables purchased		(1,194	)		(6,628	)		(8,469	)		(7,511	)
Discount from face amount of purchased receivables		9			35			44			27
Program fees paid		(9	)		(32	)		(40	)		(23	)
Servicing fees paid		(1	)		(3	)		(4	)		(4	)
Increase (decrease) in subordinated notes payable		(120	)		305			10			(136	)
Oncor’s repurchase of receivables previously sold		113			—			—			—
Operating cash flows used by (provided to) EFH Corp. under the program	$	336		$	(72	)	$	44		$	(197	)

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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 financials 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			Predecessor
	December 31, 2007			December 31, 2006
Gross trade accounts receivable	$	1,494		$	1,599
Undivided interests in accounts receivable sold by TXU Receivables Company		(363	)		(627	)
Allowance for uncollectible accounts		(32	)		(13	)
Trade accounts receivable — reported in balance sheet	$	1,099		$	959

Gross trade accounts receivable at December 31, 2007 and 2006 included unbilled revenues of $477 million and $466 million, respectively.

Allowance for Uncollectible Accounts Receivable

Predecessor:
Allowance for uncollectible accounts receivable as of January 1, 2005	$	16
Increase for bad debt expense		56
Decrease for account write-offs		(68	)
Changes related to receivables sold		17
Other (a)		15
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

(a) Reflects an allowance established in 2005 for a coal contract dispute that was reversed upon settlement in 2006. See Note 15.

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Allowances related to undivided interests in receivables sold totaled $26 million at December 31, 2006 and were reported in current liabilities.

17.     SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-term Borrowings

At December 31, 2007 and 2006, the outstanding short-term borrowings of EFH Corp. and its subsidiaries consisted of the following:

	Successor				Predecessor
	December 31, 2007				December 31, 2006
	Outstanding Amount		Interest Rate (a)		Outstanding Amount		Interest Rate (a)
Borrowings under credit facilities	$	1,718	5.39	%	$	195	5.97	%
Commercial paper		—	—			1,296	5.53	%
Total	$	1,718			$	1,491

(a) Weighted average interest rate at the end of the period.

At December 31, 2007, borrowings under credit facilities totaled $1.280 billion for Oncor and $438 million for TCEH. At December 31, 2006, outstanding commercial paper totaled $623 million for TCEH and $673 million for Oncor. All commercial paper borrowings matured prior to the Merger.

Credit Facilities

EFH Corp.’s credit facilities with cash borrowing and/or letter of credit availability at December 31, 2007 are presented below. All these facilities were entered into on October 10, 2007, and the TCEH facilities are all senior secured facilities.

Authorized Borrowers and Facility	Maturity Date	At December 31, 2007
		Facility       Limit		Letters of       Credit		Cash       Borrowings		Availability
TCEH Delayed Draw Term Loan Facility (a)	October 2014	$	4,100	$	—	$	2,150	$	1,950
TCEH Revolving Credit Facility (b)	October 2013		2,700		64		—		2,636
TCEH Letter of Credit Facility (c)	October 2014		1,250		—		1,250		—
Sub-total TCEH		$	8,050	$	64	$	3,400	$	4,586
TCEH Commodity Collateral Posting Facility (d)	December 2012		Unlimited	$	—	$	820		Unlimited
Oncor Revolving Credit Facility (e)	October 2013	$	2,000	$	—	$	1,280	$	720

(a)	Facility to be used during the two-year period commencing on October 10, 2007 to fund expenditures for constructing new generation facilities and environmental upgrades of existing generation facilities, including previously incurred expenditures not yet funded under this facility. A total of $2.15 billion was drawn at the closing of the Merger. Borrowings are classified as long-term debt.
(b)	Facility to be used for letters of credit and borrowings for general corporate purposes.
(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 $1.241 billion issued as of December 31, 2007 are supported by the restricted cash, and the remaining letter of credit availability totals $9 million.
(d)	Revolving facility to be used to fund cash collateral posting requirements under certain specified natural gas hedging transactions and general corporate purposes. A total of $382 million was drawn at the closing of the Merger and is recorded as long-term debt. Cash borrowings totaling $438 million at December 31, 2007 are classified as short-term borrowings.
(e)	Facility to be used by Oncor for its general corporate purposes. None of the borrowings were used to fund the Merger.

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On October 10, 2007, TCEH and Oncor repaid in full all outstanding borrowings totaling $2.440 billion, together with interest and all other amounts due in connection with such repayment, under their $6.5 billion of credit facilities terminated in connection with the Merger. TCEH’s and Oncor’s outstanding borrowings under these pre-Merger facilities totaled $2.055 billion and $385 million, respectively. Amounts used under the pre-Merger credit facilities at December 31, 2006, all of which related to TCEH, totaled $195 million in outstanding cash borrowings and $947 million of letters of credit.

Pursuant to PUCT rules, TCEH is required to maintain available capacity under its credit facilities in order to permit TXU Energy to return retail customer deposits, if necessary. As a result, at December 31, 2007, the total availability under the TCEH credit facilities should be further reduced by $124 million.

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Long-Term Debt

At December 31, 2007 and 2006, the long-term debt of EFH Corp. consisted of the following:

	Successor			Predecessor
	December 31, 2007			December 31, 2006
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
3.600% Floating Series 2001A due October 1, 2030 (b)		71			71
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011 (a)		217			217
3.600% Floating Series 2001D due May 1, 2033 (b)		268			268
4.950% Floating Taxable Series 2001I due December 1, 2036 (b)		62			62
3.600% Floating Series 2002A due May 1, 2037 (b)		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
3.850% Floating Series 2006A due November 1, 2041 (interest rate in effect at March 31, 2007) (c)		—			47
3.850% Floating Series 2006B due November 1, 2041 (interest rate in effect at March 31, 2007) (c)		—			46
Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028		14			14
3.850% Floating Series 2006 due November 1, 2041 (interest rate in effect at March 31, 2007) (c)		—			50
Unamortized fair value discount related to pollution control revenue bonds (l)		(175	)		—
Senior Secured Facilities:
8.396% TCEH Initial Term Loan Facility maturing October 10, 2014 (d)(e)		16,409			—
8.378% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (d)(e)		2,150			—
8.396% TCEH Letter of Credit Facility maturing October 10, 2014 (e)		1,250			—
4.473% TCEH Commodity Collateral Posting Facility maturing October 10, 2012 (e)(f)		382			—
Other:
10.25% Fixed Senior Notes due November 1, 2015		3,000			—
10.25% Fixed Senior Notes Series B due November 1, 2015		2,000			—
10.50 / 11.25% Senior Toggle Notes due November 1, 2016		1,750			—
6.125% Fixed Senior Notes due March 15, 2008 (g)		3			250
7.000% Fixed Senior Notes due March 15, 2013 (g)		5			1,000
7.100% Promissory Note due January 5, 2009		65			—
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		78			85
Capital lease obligations		161			98
Fair value adjustments related to interest rate swaps		—			10
Unamortized fair value discount (l)		(9	)		5
Total TCEH		28,604			3,126

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	Successor			Predecessor
	December 31, 2007			December 31, 2006
EFC Holdings
7.170% Fixed Senior Debentures due August 1, 2007		—			10
9.580% Fixed Notes due in semiannual installments through December 4, 2019		59			62
8.254% Fixed Notes due in quarterly installments through December 31, 2021		56			59
5.711% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (e)		1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037		8			8
Unamortized fair value discount (l)		(14	)		—
Total EFC Holdings		110			140
EFH Corp.
10.875% Fixed Senior Notes due November 1, 2017		2,000			—
11.25 / 12.00% Senior Toggle Notes due November 1, 2017		2,500			—
6.375% Fixed Senior Notes Series C due January 1, 2008 (h)		200			200
4.800% Fixed Senior Notes Series O due November 15, 2009 (g)		3			1,000
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
6.743% Floating Convertible Senior Notes due July 15, 2033 (j)		—			25
8.820% Building Financing due semiannually through February 11, 2022 (i)		88			99
Fair value adjustments related to interest rate swaps		—			(73	)
Unamortized discount		—			(9	)
Unamortized fair value premium related to Building Financing (l)		24			—
Unamortized fair value discount (l)		(714	)		—
Total EFH Corp.		6,601			3,742
Oncor
6.375% Fixed Senior Notes due May 1, 2012		700			700
7.000% Fixed Senior Notes due May 1, 2032		500			500
6.375% Fixed Senior Notes due January 15, 2015		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
5.000% Fixed Debentures due September 1, 2007		—			200
7.000% Fixed Debentures due September 1, 2022		800			800
Unamortized discount		(15	)		(16	)
Total Oncor		2,835			3,034
Oncor Electric Delivery Transition Bond Company LLC (k)
2.260% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2007		—			8
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		93			122
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		99			158
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		978			1,074
Unamortized fair value discount related to transition bonds (l)		(12	)		—
Total Oncor consolidated		3,801			4,108
Total EFH Corp. consolidated		39,116			11,116
Less amount due currently		(513	)		(485	)
Total long-term debt	$	38,603		$	10,631

(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 December 31, 2007. These series are in a weekly interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(c) These series were redeemed on May 8, 2007 as a result of the suspension of development of eight coal-fueled generation facilities.

(d) Interest rate swapped to fixed on $15.05 billion principal amount. Initial borrowings under the TCEH Initial Term Loan Facility totaled $16.450 billion, of which TCEH repaid $41 million in December 2007 as required by the credit agreement.

(e) Interest rates in effect at December 31, 2007.

(f) See “Credit Facilities” above for more information.

(g) EFH Corp. commenced offers to purchase and consent solicitations for these series on September 25, 2007. EFH repurchased the majority of the bonds in October 2007.

(h) Interest rates swapped to variable on entire principal amount at December 31, 2007.

(i) EFH Corp. and TCEH replaced their guarantees of this financing with a $144 million letter of credit in June 2007, which has since been reduced to $135 million.

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(j) Interest rates in effect at December 31, 2007. In conjunction with the Merger, a supplemental indenture was executed and provided that this series become payable in cash. On October 25, 2007, substantially all of these notes were converted and redeemed.

(k) These bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset.

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

Long-Term Debt-Related Activity—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.

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Maturities— Long-term debt maturities as of December 31, 2007 are as follows (includes Oncor’s transition bond semi-annual payments):

Year
2008	$	468
2009		420
2010		423
2011		931
2012		1,105
Thereafter		36,523
Unamortized fair value premium		24
Unamortized fair value discount		(924	)
Unamortized discount		(15	)
Capital lease obligations		161
Total	$	39,116

TCEH Senior Secured Facilities — Borrowings, including letters of credit 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 $19.873 billion at December 31, 2007, 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 commencing after delivery of the financial statements for the first quarter ending March 31, 2008, under which the applicable margins may be reduced based on the achievement of certain leverage ratio levels.

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 will be subject to reduction, commencing after delivery of the financial statements for the first quarter ending March 31, 2008, based on the achievement of certain leverage ratio 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 the first anniversary of October 10, 2007, 1.25% per annum, and thereafter, 1.50% per annum.

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.

136

The TCEH Senior Secured Facilities, including the guarantees thereof, certain commodity hedging transactions (including those that were formerly secured by a first-lien on the Big Brown plant) 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 requires TCEH and its restricted subsidiaries to maintain 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 beginning on December 31, 2007 in an aggregate annual amount equal to 1% of the original principal amount of such facility, 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 the last day of the first fiscal quarter to occur after October 10, 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.

TCEH Senior Unsecured Interim Facilities—On October 10, 2007, TCEH and TCEH Finance entered into senior unsecured credit facilities with borrowings of $6.75 billion. All amounts outstanding under this facility were repaid using proceeds from the issuances of $3.0 billion of cash-pay senior notes on October 31, 2007 and $2.0 billion of cash-pay senior notes and $1.75 billion of toggle senior notes on December 6, 2007 described immediately below.

TCEH Notes Issued Subsequent to the Merger—Pursuant to an indenture entered into on October 31, 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. On December 6, 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 will be made on May 1, 2008.

137

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) will be payable 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 (PIK Interest); or (iii) 50% in cash 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 will be made on May 1, 2008.

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. 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. 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;

• engage in mergers or consolidations;

• permit dividend and other payment restrictions on restricted subsidiaries, and

• engage in certain transactions with affiliates.

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.

138

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 and have not been registered under the Securities Act of 1933, as amended (the Securities Act). The Co-Issuers have agreed to use their commercially reasonable efforts to register with the SEC notes having substantially identical terms as the TCEH Notes as part of an offer to exchange freely tradable exchange notes for the TCEH Notes. The Co-Issuers have 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 360 days after the issue date of the TCEH Notes. If this obligation is not satisfied (a TCEH Registration Default), the annual interest rate on the TCEH Notes will increase by 0.25% per annum for the first 90-day period during which a Registration Default continues, and thereafter the annual interest rate on the TCEH Notes will increase by 0.50% per annum over the original interest rate for the remaining period during which the TCEH Registration Default continues. If the TCEH Registration Default is cured, the applicable interest rate on such TCEH Notes will revert to the original level.

EFH Corp. Senior Unsecured Interim Facility— On October 10, 2007, in connection with the Merger and the repayment of certain existing indebtedness, EFH Corp. entered into a senior unsecured credit facility with borrowings of $4.5 billion. All amounts outstanding under this facility were repaid on October 31, 2007 using proceeds from the issuances of $2.0 billion of EFH Corp. cash-pay senior notes and $2.5 billion of EFH Corp. toggle senior notes described immediately below as well as some cash on hand.

EFH Corp. Notes Issued Subsequent to the Merger— Pursuant to an indenture entered into on October 31, 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 will be 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) will be payable 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 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 will be made on May 1, 2008.

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 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;

• engage in mergers or consolidations;

• 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 with the net cash proceeds of certain equity offerings 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 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 and have not been registered under the Securities Act. EFH Corp. has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFH Corp. Notes as part of an offer to exchange freely tradable exchange notes for the EFH Corp. Notes. EFH Corp. 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 360 days after the issue date of the EFH Corp. Notes. If this obligation is not satisfied (an EFH Corp. Registration Default), the annual interest rate on the EFH Corp. Notes will increase by 0.25% per annum for the first 90-day period during which an EFH Corp. Registration Default continues, and thereafter the annual interest rate on the EFH Corp. Notes will increase by 0.50% per annum over the applicable original interest rate for the remaining period during which the EFH Corp. Registration Default continues. If the EFH Corp. Registration Default is cured, the applicable interest rate on such EFH Corp. Notes will revert to the original level.

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Intercreditor Agreement— On October 10, 2007, in connection with the Merger, TCEH entered into an Intercreditor Agreement (the Intercreditor Agreement) with Citibank, N.A. and four 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 Credit Agreement. 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 Hedges—In the 2007 Successor period, 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 are being accounted for as cash flow hedges related to variable interest rate cash flows. Based on the fair value of the positions, the interest rate swaps were $280 million out-of-the-money at December 31, 2007. This amount is reflected in the balance sheet as a derivative contract liability with the offset to accumulated other comprehensive income. No ineffectiveness gains or losses have been recorded.

Oncor Revolving Credit Facility— On October 10, 2007, Oncor entered into a $2.0 billion revolving 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. None of the borrowings under this facility were used to fund the Merger.

Borrowings under this facility totaled $1.280 billion at December 31, 2007, primarily representing the funding of the repayment on October 10, 2007 of $385 million of borrowings under Oncor’s pre-Merger credit facilities and $800 million aggregate principal amount of floating rate senior notes required to be repaid as a result of the Merger. 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.

Borrowings 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%). Based on Oncor’s current ratings, its LIBOR-based borrowings will bear interest at LIBOR plus 0.575%.

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 0.175%. 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 facility contains customary covenants for facilities of this type, restricting, subject to certain exceptions, Oncor and its subsidiaries from, among other things:

• incurring additional liens;

• entering into mergers and consolidations;

• selling assets, and

• making acquisitions and investments in subsidiaries.

In addition, the 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.

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The 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.

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.

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 due January 5, 2009 at a fixed interest rate of 7.100%, which has been reported as long-term debt.

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 a liability of $52 million reported as long-term debt. TCEH also entered into leases related to mining equipment that have been accounted for as capital leases of $7 million, $10 million and $6 million in September, October and December 2007, respectively.

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 canceled. 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.

Debt-Related Activity in 2006— In November 2006, upon the scheduled mandatory tender date, TCEH repurchased all of the Trinity River Authority of Texas Series 2001A and Brazos River Authority Series 2001B pollution control revenue bonds with aggregate principal amounts of $37 million and $19 million, respectively, at a price of 100% of the principal amount thereof. TCEH currently plans to remarket these bonds.

In June 2006, upon the scheduled mandatory tender date, TCEH repurchased all of the Brazos River Authority Pollution Control Revenue (Refunding) Bonds Series 1995B with an aggregate principal amount of $114 million at a price of 100% of the principal amount thereof. TCEH currently plans to remarket these bonds.

In May 2006, upon the scheduled mandatory tender date, TCEH repurchased all of the Brazos River Authority Pollution Control Revenue (Refunding) Bonds Series 1994B and 1995A with aggregate principal amounts of $39 million and $50 million, respectively, at a price of 100% of the principal amounts thereof. TCEH currently plans to remarket these bonds.

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In May 2006, the equity-linked Series M Senior Notes with an aggregate principal amount of $179 million were remarketed to fund the settlement of the associated common stock purchase contracts. EFH Corp. participated in the remarketing and purchased all of the outstanding Series M Senior Notes at a price of 100.5% of par and immediately retired the notes resulting in a loss on retirement of $1 million.

In March 2006, TCEH issued the Brazos River Authority Series 2006 Pollution Control Revenue Bonds with an aggregate principal amount of $100 million. The bonds have a fixed interest rate of 5.0% and mature in March 2041. Net proceeds of $100 million (principal amount less issuance expenses) from the issuance are held in a trust and, along with related earned interest, are classified as restricted cash. Such proceeds will be released to TCEH by the trust at such time as documentation of qualified expenditures are presented and approved by the trustee.

Other retirements of long-term debt in 2006 totaling $1.3 billion represented payments at scheduled maturity dates and included $733 million of EFH Corp. senior notes and $400 million of TCEH senior 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, 2006 — net reduction in debt carrying value (net out-of-the-money value of swaps)	$	(44	)
Fair value adjustments during the period		(13	)
Recognition of net gains on settled fair value hedges (a)		(6	)
Long-term debt fair value adjustments at December 31, 2006 — net reduction in debt carrying value		(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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18.    COMMITMENTS AND CONTINGENCIES

Generation Development

Subsidiaries of EFH Corp. have executed EPC agreements for the development of three lignite coal-fueled generation units in Texas. Such subsidiaries or the EPC contractors have placed orders for critical long lead-time equipment, including boilers, turbine generators and air quality control systems for the two units at Oak Grove and one unit at Sandow, and construction of the three units is underway.

In September 2007, a subsidiary of EFH Corp. acquired from Alcoa Inc. the air permit related to the Sandow facility that had been previously issued by the TCEQ. However, the air permit is the subject of an appeal as discussed below under “Litigation—Generation Facilities.”

A subsidiary of EFH Corp. has received the air permit for the Oak Grove units, which was approved by the TCEQ in June 2007. However, the air permit is the subject of an appeal and litigation as discussed below under “Litigation—Generation Facilities.”

Construction work-in-process assets balances for the three generation units totaled approximately $2.8 billion as of December 31, 2007, which includes the effects of the fair value adjustments related to purchase accounting. If construction-related agreements for the three generation units had been canceled as of that date, subsidiaries of EFH Corp. would have incurred an estimated termination obligation of up to approximately $400 million. This estimated gross cancellation exposure of approximately $3.2 billion at December 31, 2007 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, 2007, EFH Corp. had noncancelable 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
2008	$	219	$	45	$	73	$	112	$	8
2009		149		48		—		161		8
2010		43		41		—		54		8
2011		43		40		—		51		8
2012		—		81		—		154		8
Thereafter		—		—		—		259		50
Total	$	454	$	255	$	73	$	791	$	90

(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)
2008	$	27	$	52
2009		25		52
2010		25		51
2011		68		48
2012		11		45
Thereafter		55		339
Total future minimum lease payments		211	$	587
Less amounts representing interest		50
Present value of future minimum lease payments		161
Less current portion		17
Long-term capital lease obligation	$	144

(a) Includes operating leases with initial or remaining noncancelable 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 2008, $17 million in 2009, $17 million in 2010, $17 million in 2011, $17 million in 2012 and $34 million in periods thereafter.

Rent charged to operating cost, fuel cost and SG&A totaled $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 and $112 million for the years ended December 31, 2006 and 2005, respectively.

Litigation-Merger Related

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. On April 27, 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. The Merger Agreement allowed EFH Corp. to solicit other proposals from third parties until April 16, 2007 and the transaction was subject to the approval of EFH Corp.’s former shareholders, which was obtained at the annual meeting of shareholders on September 7, 2007. Accordingly, 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. The Motions are pending before the Court. No further action has been taken by the parties, and the Court has not yet ruled upon the Written Statement and Application, given the memorandum of understanding executed by the parties on July 23, 2007 and the proposed settlement as described below.

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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, allege that EFH Corp.’s former directors, named as defendants, breached fiduciary duties owed EFH Corp. by approving the Merger Agreement. The petitions, now consolidated into one action in the 44^th District Court, Dallas County, Texas, include claims that the defendants failed to ensure that the transaction was in the best interest of EFH Corp.; that the former directors participated in a transaction 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. EFH Corp. believes that the Plaintiffs failed to comply with provisions of the TBOC applicable to filing and pursuing derivative proceedings and filed a Motion to Dismiss that is pending before the Court. Additionally, EFH Corp. filed a Written Statement with the Court advising that, pursuant to the TBOC, a Derivative Demand Committee of independent and disinterested former members of EFH Corp.’s board of directors has been formed and is engaged in the active review, in good faith, of the allegations in the consolidated derivative lawsuits. EFH Corp. also requested that the Court enforce the automatic and mandatory stay of the proceedings as provided in the TBOC until the Derivative Demand Committee has completed its review. On May 16, 2007, the parties agreed to stay the consolidated derivative proceeding pending the Derivative Demand Committee’s review of Plaintiffs’ claims in that proceeding. On May 18, 2007, the Court entered an order staying the action in accordance with Section 21.555 of the TBOC. On July 18, 2007, EFH Corp. filed a Written Statement pursuant to TBOC Section 21.555(c) and an Application for Additional Stay informing the District Court that the Derivative Demand Committee was continuing its active review, in good faith, of the allegations set forth in the derivative lawsuits and accordingly requested an extension of the order staying the action through August 31, 2007. No further action has been taken by the parties, and the Court has not yet ruled upon the Written Statement and Application, given the memorandum of understanding executed by the parties on July 23, 2007 and the proposed settlement as described below.

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, as well as a request 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. The Merger Agreement allowed EFH Corp. to solicit other proposals from third parties until April 16, 2007 and was subject to the approval of EFH Corp.’s former shareholders, which was obtained at the annual meeting of shareholders on September 7, 2007. The consolidated suit purports to assert claims by shareholders directly against the directors. EFH Corp. believes that Texas law does not recognize such a cause of action. Consequently, EFH Corp. and its former directors filed a Motion to Dismiss. On May 25, 2007, the Court granted the Motion and dismissed the consolidated putative class action suit with prejudice. On May 31, 2007, Plaintiffs moved for reconsideration of the May 25 Order dismissing the action; however, Plaintiffs subsequently withdrew this motion. No further action has been taken by the parties, and the Court has not yet ruled upon the Written Statement and Application, given the memorandum of understanding executed by the parties on July 23, 2007 and the proposed settlement as described below.

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On July 19, 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 June 14, 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. EFH Corp. has not yet responded to this litigation and, as described below, on July 23, 2007, the Sponsor Group, joined by EFH Corp. for the limited purpose described below, have entered into a memorandum of understanding with plaintiffs that would result in the dismissal of this litigation if the settlement is approved by the courts. In the event that EFH Corp. is required to respond to this litigation, EFH Corp. will file a Motion to Dismiss based on the fact that this proxy statement clearly and accurately described the information regarding the Merger and the information necessary for a shareholder to evaluate the proposal to approve the Merger Agreement. EFH Corp. believes the claims made in this litigation are without merit and, therefore, if necessary, EFH Corp. intends to vigorously defend this litigation.

On July 23, 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, if approved by the court in which the litigation is pending, to the extent required, all of the litigation related to the Merger described above will be 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 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 on October 10, 2007, EFH Corp. merged with the entity obligated to fund any court approved attorneys’ fees. Accordingly, EFH Corp. is legally obligated for such payment. On January 7, 2008, a final settlement agreement was executed by the Plaintiffs in the above described litigation matters, and the defendants and the courts with jurisdiction over the litigation are scheduled to consider the settlements for approval on April 18, 2008. The settlement of the litigation, subject to court approval, will result in a dismissal of all claims related to the Merger against EFH Corp. and its preclosing officers and directors.

Litigation-Generation Facilities

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 on September 7, 2007 in the State District Court of Travis County, Texas. Plaintiffs ask that the District Court reverse TCEQ’s approval of the Oak Grove air permit; TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments; and remand the matter back to TCEQ for further proceedings. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before 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 have filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to SOAH for further proceedings. 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.

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On December 1, 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 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 allege 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 on June 13, 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 on May 21, 2007. The Plaintiffs have appealed the District Court’s dismissal of the case to the Fifth Circuit Court of Appeals and oral argument was heard in the appeal on March 3, 2008. EFH Corp. believes the District Court properly granted the Motion to Dismiss and while EFH Corp. is unable to estimate any possible loss or predict the outcome of this litigation in the event the Fifth Circuit Court of Appeals reverses the District Court, EFH Corp. maintains that the claims made in the complaint are without merit. Accordingly, EFH Corp. intends to vigorously defend the appeal and this litigation in the event the Fifth Circuit reverses the District Court.

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 have appealed the district court’s decision to the Fifth Circuit Court of Appeals. There can be no assurance that the outcome of this matter would not result in an adverse impact on the Sandow 5 project. EFH Corp. believes the claims on appeal are without merit and will vigorously defend the appeal.

Litigation-Other

On September 6, 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. 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 on August 30, 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 which is pending before the District Court. 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, including the appeal of the District Court’s order dismissing the litigation.

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In November 2002, February 2003 and March 2003, three lawsuits were filed in the US District Court for the Northern District of Texas, Dallas Division, asserting claims under Employee Retirement Income Security Act (ERISA) on behalf of a putative class of participants in and beneficiaries of various employee benefit plans of EFH Corp. (then known as TXU Corp.). These ERISA lawsuits were consolidated, and a consolidated complaint was filed in February 2004 against EFH Corp., former directors of EFH Corp. serving during the putative class period as well as certain officers of EFH Corp. who were the members of the TXU Thrift Plan Committee. The plaintiffs seek to represent a class of participants in such employee benefit plans during the period between April 26, 2001 and October 11, 2002. The plaintiffs filed an initial motion for class certification and, after class certification discovery was completed, the District Court denied plaintiffs’ initial class certification motion without prejudice and granted plaintiffs’ leave to amend their complaint. Plaintiffs’ second class certification motion, filed on the basis of their amended complaint, was denied, and the case was ordered dismissed without prejudice on September 29, 2005. The plaintiffs filed an appeal of the dismissal to the Fifth Circuit Court of Appeals. While on appeal, the matter was referred to the Fifth Circuit’s alternative dispute resolution program and subsequently to mediation. While mediation was unsuccessful, further discussions led to an agreement in principle to settle this litigation on December 24, 2006 for $7.25 million, before attorneys’ fees, to be paid by EFH Corp. to the Thrift Plan pursuant to a Court approved allocation. A Memorandum of Understanding confirming the agreement in principle was signed on January 24, 2007, a final settlement agreement was signed in September 2007 and the court entered an Order Granting Preliminary Approval of the settlement on December 12, 2007. On March 25, 2008, the District Court entered an order approving the settlement as well as a final judgment. No objections to the settlement were filed. Accordingly, EFH Corp. does not expect an appeal.

Regulatory Investigations

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 is 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. A hearing requested by Luminant Energy to contest the alleged occurrence of a violation and the amount of the penalty in the NOV was scheduled to start in April 2008 but was stayed pending resolution of discovery disputes and Luminant Energy’s motion to dismiss, which was filed in November 2007. That motion was denied by the state administrative law judges, and in February 2008 the PUCT declined to hear Luminant Energy’s appeal of that denial. On March 26, 2008, Luminant Energy submitted to the administrative law judges its motion for summary decision on the discrete legal issue of what the maximum lawful penalty calculation could be in this proceeding. EFH Corp. believes Luminant Energy’s conduct during the period in question was consistent with the PUCT’s rules and policies, and no market power abuse was committed. EFH Corp. is vigorously contesting the NOV. EFH Corp. is unable to predict the outcome of this matter.

EFH Corp. and Luminant Energy have taken actions to reduce the risk of future similar allegations related to the balancing energy segment of the ERCOT wholesale market, including working with the PUCT Staff and the PUCT’s independent market monitor to develop a voluntary mitigation plan for approval by the PUCT. Luminant Energy has submitted a voluntary mitigation plan that was approved by the PUCT in July 2007. The PUCT’s approval action was challenged by some other market participants on procedural grounds, and a Texas District Court upheld that challenge. The PUCT did not appeal that ruling.

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Commitment to Fund Demand Side Management Initiatives

Related to 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. See Note 10 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. See Note 10 for additional information regarding the stipulation with the PUCT.

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. Also in January 2008, a new two-year agreement was reached covering bargaining unit personnel engaged in lignite mining operations. Existing agreements for bargaining unit personnel engaged in the nuclear and lignite/coal-fueled generation are in effect until August and November 2008, respectively. Negotiations are currently underway with respect to the collective bargaining agreements covering bargaining unit personnel engaged in the Three Oaks Mine and Sandow lignite-fueled generation operations. The existing Oncor bargaining agreement expired in January 2008, and a new three-year contract was ratified in February 2008. Management 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.

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.

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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 for certain qualified environmental claims arising in relation to the assets acquired by Atmos Energy Corporation. This environmental indemnity expired on October 1, 2007. In addition, until October 1, 2014, EFH Corp. agreed to indemnify Atmos Energy Corporation 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 Energy Corporation, 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 Energy Corporation 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 facilities. At December 31, 2007, the aggregate maximum amount of residual values guaranteed was approximately $91 million with an estimated residual recovery of approximately $89 million. These leased assets consist primarily of mining equipment, rail cars and vehicles. The average life of the lease portfolio is approximately four years. See Note 17 regarding the refinancing of an operating lease of certain rail cars.

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, 2007, the balance of the indebtedness was $114 million with maturities of principal and interest extending to December 2021. The indebtedness is secured by a lien on the purchased facilities.

Security Interest

In 2006, a first-lien interest was placed on the two lignite/coal-fueled generation units at TCEH’s Big Brown plant to support commodity hedging transactions entered into by Generation Development Company LLC (a direct, wholly-owned subsidiary of EFH Corp. that also holds assets related to cancelled generation facilities previously under development). In connection with the closing of the Merger, the hedge transactions were transferred to TCEH and became secured by a first-lien interest in substantially all of the assets of TCEH and its subsidiaries, and the prior lien on the Big Brown plant was released. See Note 17 for additional details.

Letters of Credit

At December 31, 2007, TCEH had outstanding letters of credit under its credit facilities totaling $1.305 billion as follows:

• $592 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions;

• $455 million to support (and available to fund payment of) floating rate pollution control revenue bond debt of $446 million principal amount;

• $135 million to support obligations under the lease agreement for EFH Corp.’s headquarters building;

• $52 million to support mining reclamation activities, and

• $71 million for miscellaneous credit support requirements.

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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 is 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 $10.8 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 $10.8 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 $100.6 million plus a 3% insurance premium tax, subject to increases for inflation every five years. Assessments are limited to $15 million per operating licensed reactor per year per incident. EFH Corp.’s maximum potential assessment under the industry retrospective plan would be $201.2 million (excluding taxes) per incident but no more than $30 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 $3.5 billion (subject to $1 million deductible per accident), above which EFH Corp. is self-insured. The $3.5 billion 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, $2.25 billion of premature decommissioning coverage provided by NEIL and $737 million of other property damage coverage from other insurance markets and foreign nuclear insurance pools.

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 total $14.5 million for primary property, $14.1 million for excess property and $8.3 million for accidental outage.

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Also, under the NEIL policies, if there were multiple terrorism losses occurring within a one-year time frame, NEIL would make available one industry aggregate limit of $3.2 billion plus any amounts it recovers from other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply. Under the ANI liability policy, the liability arising out of terrorist acts will be subject to one industry aggregate limit of $300 million that could be reinstated at ANI’s option depending on prevailing risk circumstances and the balance in the Industry Credit Rating Plan reserve fund. Under the US Terrorism Risk Insurance Extension Act of 2005, the US government provides reinsurance with respect to acts of terrorism in the US for losses caused by an individual or individuals acting on behalf of foreign parties. In such circumstances, the NEIL and ANI terrorism aggregates would not apply.

19.    SHAREHOLDERS’ EQUITY

Successor

Equity Contributions — 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 addition, as of December 31, 2007 certain members of management of EFH Corp. and its subsidiaries committed to equity contributions aggregating approximately $28 million in exchange for approximately 5.6 million shares of common stock in EFH Corp. Through March 14, 2008, an additional $3 million was contributed for an additional 0.6 million shares.

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.

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.

Stock Split —In 2005, EFH Corp.’s board of directors declared a two-for-one stock split effected in the form of a 100 percent stock dividend. The stock split entitled each shareholder of record at the close of business on November 18, 2005, to receive one additional share for every outstanding share of common stock they held on that date. The additional shares resulting from the stock split were distributed on December 8, 2005.

Common Stock Repurchase—In November 2005 and November 2006, EFH Corp.’s board of directors authorized the repurchase of up to 54 million shares of common stock through the end of 2007. Under these authorities, approximately 31 million shares were repurchased, including 12 million shares in November 2005, 19 million shares during the twelve months ended December 31, 2006 and 0.2 million shares during the period from January 1, 2007 through October 10, 2007 at an average price of $49.51, $51.77 per share and $64.80, respectively (including related fees and expenses).

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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.

Accelerated Share Repurchase Program —In November 2004, EFH Corp. entered into an agreement with a broker-dealer counterparty under which EFH Corp. repurchased and retired 105 million shares of its outstanding common stock at an initial price of $32.29 per share for a total of $3.4 billion. Under the agreement, the counterparty immediately borrowed shares that were sold to and canceled by EFH Corp. and in turn purchased shares in the open market over a subsequent time period; the agreement was subject to a future contingent purchase price adjustment based on the actual price of the shares purchased by the counterparty. In May 2005, EFH Corp. paid $523 million (including related fees and expenses) in cash to the counterparty in full settlement of the transaction. The counterparty had repurchased the shares under the agreement at an average price per share of $36.91.

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, $17 million in 2006 and $19 million in 2005.

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.

EFH Corp. Preference Stock —In June 2005, EFH Corp. redeemed for cash all 3,000 shares of its Series B preference stock outstanding (liquidation preference of $100,000 per share) at the aggregate principal amount of $300 million. The preference stock had a dividend rate of 7.24%.

EFC Holdings’ Preferred Stock —In August 2005, EFC Holdings redeemed all 379,231 shares of its outstanding preferred stock with a stated value of $38 million for approximately $40 million in cash, including principal, premium and accrued dividends. The preferred stock had dividend rates ranging from $4.00 to $5.08 per share. In December 2005, EFC Holdings reissued 788 shares of its $4.56 Series preferred stock in private placement transactions. In October 2007 prior to the Merger, EFC Holdings issued an additional 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.

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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		Twelve months ended December 31, 2005
Balance at beginning of period	459,244,523		470,845,978		479,705,760
Issuances under equity-linked debt securities	—		5,683,791		2,708,250
Issuances under stock-based incentive compensation plans (Note 23)	2,771,257		2,200,766		1,093,480
Issued on conversion of convertible senior notes	36,372		—		9,716
Repurchases	—		(18,165,403	)	(12,476,228	)
Forfeitures and cancellations under stock-based incentive compensation plan	(900,143	)	(1,320,609	)	(195,000	)
Purchased in connection with Merger	(461,152,009	)	—		—
Balance at end of period	—		459,244,523		470,845,978

20.    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, 2007
	Commodity contracts			Cash flow hedges and other derivatives			Netting adjustments (a)			Total
Assets:
Current assets	$	269		$	11		$	—		$	280
Noncurrent assets		68			5			—			73
Total	$	337		$	16		$	—		$	353
Liabilities:
Current liabilities	$	193		$	104		$	—		$	297
Noncurrent liabilities		2,061			221			—			2,282
Total	$	2,254		$	325		$	—		$	2,579
Net assets (liabilities)	$	(1,917	)	$	(309	)	$	—		$	(2,226	)
	Predecessor
	December 31, 2006
	Commodity contracts			Cash flow hedges and other derivatives			Netting adjustments (a)			Total
Assets:
Current assets	$	276		$	698		$	(24	)	$	950
Noncurrent assets		162			248			(65	)		345
Total	$	438		$	946		$	(89	)	$	1,295
Liabilities:
Current liabilities	$	278		$	39		$	(24	)	$	293
Noncurrent liabilities		183			73			(65	)		191
Total	$	461		$	112		$	(89	)	$	484
Net assets (liabilities)	$	(23	)	$	834		$	—		$	811

(a) Represents the effects of netting assets and liabilities at the counterparty agreement level where the legal right of offset exists.

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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 in net income.

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.

Predecessor results include “day one” losses of $231 million associated with contracts entered into in 2007 at below market prices. Successor results include a “day one” loss of $8 million associated with a contract entered into in 2007 at below market prices. Essentially all of this amount represents losses associated with a transaction using natural gas financial instruments intended to economically hedge exposure to future changes in electricity prices. The losses were recorded as a reduction of revenues, consistent with other mark-to-market gains and losses, and were included in the results of the Competitive Electric segment. The “day one” losses were recorded as commodity contract liabilities.

Predecessor results include a “day one” gain of $30 million associated with a long-term power purchase agreement entered into in 2007. The gain was recorded as an increase to revenues, consistent with other mark-to-market gains and losses, and was included in the results of the Competitive Electric segment. The “day one” gain was recorded as a commodity contract asset.

Cash Flow Hedge and Other Derivative Assets and Liabilities

Cash flow hedge and other derivative assets and liabilities primarily represent fair values of commodity contracts and interest rate swaps that have been designated as cash flow hedges. The change in fair value of derivative assets and liabilities designated as cash flow hedges are recorded as other comprehensive income or loss to the extent the hedges are effective; the ineffective portion of the change in fair value is included in net income. See Note 17 for details of interest rate swaps entered into subsequent to the Merger and designated as cash flow hedges.

A significant portion of natural gas financial instruments entered into to hedge future changes in electricity prices had 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.

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A summary of cash flow hedge and other derivative assets and liabilities follows:

	Successor		Predecessor
	December 31, 2007		December 31, 2006
Current and noncurrent assets:
Commodity-related cash flow hedges	$	8	$	933
Interest rate swaps		8		4
Other		—		9
Total	$	16	$	946
Current and noncurrent liabilities:
Commodity-related cash flow hedges	$	1	$	23
Interest rate swaps		324		89
Total	$	325	$	112

Other Cash Flow Hedge Information— EFH Corp. experienced cash flow hedge ineffectiveness of $114 million in net gains in 2007 (essentially all of which was in the Predecessor period), $218 million in net gains in 2006 and $38 million in net losses in 2005. These amounts are pretax and are reported in revenues.

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 $90 million in net gains in 2007 (essentially all of which was in the Predecessor period), $239 million in net gains in 2006 and $27 million in net losses in 2005.

As of December 31, 2007, commodity positions accounted for as cash flow hedges, which represent a small portion of economic hedge positions, reduce exposure to variability of future cash flows from future revenues or purchases through 2010.

Cash flow hedge amounts reported in accumulated other comprehensive income are recognized in earnings as the related forecasted transactions are settled or become probable of not occurring. No amounts were reclassified into earnings in 2007, 2006 or 2005 as a result of the discontinuance of cash flow hedge accounting because a hedged forecasted transaction became probable of not occurring.

Cash flow hedge amounts reported in the Statements of Consolidated Comprehensive Income exclude net gains and losses associated with cash flow hedges entered into and settled within the periods presented. These amounts totaled less than $1 million in after-tax net losses for the period from October 11, 2007 through December 31, 2007, $19 million in after tax net losses for the period from January 1, 2007 through October 10, 2007, $31 million in after-tax net gains in 2006 and $53 million in after-tax net losses in 2005.

Accumulated other comprehensive income related to cash flow hedges at December 31, 2007 totaled $177 million in net losses (after-tax), of which $182 million in net losses relates to interest rate swaps. EFH Corp. expects that $37 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of December 31, 2007 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income. Of this amount, $40 million in losses relate to interest rate swaps and $3 million in gains relate to commodity hedges.

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21.    INVESTMENTS

The balance of investments consists of the following:

	Successor		Predecessor
	December 31, 2007		December 31, 2006
Nuclear decommissioning trust	$	484	$	447
Assets related to employee benefit plans, including employee savings programs		306		197
Land		44		36
Note receivable from Capgemini		25		25
Investment in unconsolidated affiliates		2		3
Wind investment project		3		—
Miscellaneous other		4		4
Total investments	$	868	$	712

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, 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
	Predecessor
	December 31, 2006
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities	$	169	$	5	$	(1	)	$	173
Equity securities		162		117		(5	)		274
Total	$	331	$	122	$	(6	)	$	447

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

Debt securities held at December 31, 2007 mature as follows: $90 million in one to five years, $35 million in five to ten years and $70 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, 2007 and 2006, the face amount of these policies totaled $540 million and $501 million, and the net cash surrender values totaled $189 million and $167 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.

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Capgemini Agreement

In May 2004, EFH Corp. entered into a services agreement with Capgemini to outsource certain support activities. As part of the agreement, Capgemini was provided a royalty-free right, under an asset license arrangement, to use EFH Corp.’s information technology assets, consisting primarily of computer software. EFH Corp. obtained a 2.9% limited partnership interest in Capgemini in exchange for the asset license. EFH Corp. has the right to sell (the put option) its interest and the licensed software to Cap Gemini North America Inc. for $200 million, plus its share of Capgemini’s undistributed earnings, upon expiration of the services agreement or earlier upon the occurrence of certain events. Cap Gemini North America Inc. has the right to purchase these interests under the same terms and conditions. The partnership interest has been recorded at an initial value of $2.9 million and is being accounted for on the cost method.

EFH Corp. recorded the estimated fair value of the put option of $177 million in 2004, reported in the balance sheet in other noncurrent assets. Of this amount, $169 million was recorded as a reduction to the carrying value of the licensed software, and the balance, which represents the fair value of the assumed cash distributions and gains while holding the partnership interest, was recorded as a noncurrent deferred credit. This accounting is in accordance with AICPA Statement of Position 98-1, “Accounting for the Costs of Computer Software Developed or Obtained for Internal Use.”

In July 2004, EFH Corp. loaned Capgemini $25 million for working capital purposes pursuant to a promissory note that bears interest at an annual rate of 4% and matures in July 2019.

Subject to certain terms and conditions, Cap Gemini North America, Inc. and its parent, Cap Gemini S.A., have guaranteed the performance and payment obligations of Capgemini under the services agreement, as well as payments under the put option.

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 participated 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 ineligible 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.

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Adoption of SFAS 158 in 2006

In September 2006, the FASB issued SFAS 158, which was adopted by EFH Corp. effective December 31, 2006, as required. SFAS 158 requires reporting in the balance sheet of the funded status of defined benefit pension and OPEB plans. Periodic pension and OPEB costs continue to be determined in accordance with SFAS 87 and SFAS 106. Under these standards, the accrued benefit obligation recognized in the balance sheet represented the cumulative difference between the net periodic benefit costs and cash funding of the plans. SFAS 87 also required the recording of a minimum pension liability representing the excess of the accumulated benefit obligation over the fair value of the plans’ assets and the accrued benefit obligation already recorded under SFAS 87. The recording of the minimum pension liability resulted in adjustments to other comprehensive income or balance sheet accounts, principally regulatory assets.

SFAS 158 requires that both the pension and OPEB accrued benefit obligation reported in the balance sheet represent the funded status of the plans based on the projected benefit obligation, which for the pension plan takes into account future compensation increases. For EFH Corp., the initial recognition of the funded status on the financial statements was largely reflected as an increase in the accrued benefit obligation and an increase in regulatory assets. The recording of a regulatory asset, instead of a reduction in the accumulated other comprehensive income component of shareholders’ equity as set forth in SFAS 158, is based on the regulatory recovery of retirement benefits under the June 2005 amendment to PURA. See discussion below under “Regulatory Recovery of Pension and OPEB Costs”.

The following summarizes the impact on the Predecessor December 31, 2006 consolidated balance sheet of adopting SFAS 158:

	December 31, 2006
	Balances Prior to Application of SFAS 158		Increase (Decrease) in Balances			Balances After Application of SFAS 158
Pension assets	$	16	$	(7	)	$	9
Noncurrent assets:
Accumulated deferred income taxes	$	176	$	14		$	190
Regulatory assets	$	61	$	343		$	404
Current liabilities:
Defined benefit pension and OPEB obligations	$	—	$	2		$	2
Noncurrent liabilities:
Defined benefit pension and OPEB obligations	$	708	$	361		$	1,069
Shareholders’ equity:
Accumulated other comprehensive income — net	$	11	$	(13	)	$	(2	)

The amounts recorded in the fourth quarter of 2006 upon adoption of SFAS 158 were based on the measurements of EFH Corp.’s pension and OPEB plans at the December 31, 2006 year-end date, which had been EFH Corp.’s practice but is now required under SFAS 158.

The recording of the total liability did not affect any financial covenants in any Pre-Merger credit agreements.

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Minimum Pension Liability Adjustment Prior to SFAS 158

As discussed above, EFH Corp. recorded a minimum pension liability prior to the adoption of SFAS 158. The minimum pension liability recorded for the year ended December 31, 2005 totaled $112 million after-tax, of which a loss of $46 million after-tax was recorded as a charge to other comprehensive income and $66 million, net of deferred tax liability, was recorded as a regulatory asset.

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 its 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. Accordingly, in the second quarter of 2005, Oncor began deferring (principally as a regulatory asset or property) additional pension and OPEB costs as permitted by the amendment, which was retroactively effective January 1, 2005. Amounts deferred are ultimately subject to regulatory approval. Amounts recorded as a regulatory asset in 2007 totaled $20 million.

Pension and OPEB Costs Recognized as Expense

	Successor			Predecessor
	Period from October 11, 2007 through December 31,			Period From January 1, 2007 through October 10,			Year Ended December 31,
	2007			2007			2006			2005
Pension costs under SFAS 87	$	(1	)	$	34		$	66		$	46
OPEB costs under SFAS 106		11			49			81			71
Total benefit costs		10			83			147			117
Less amounts deferred principally as a regulatory asset or property		(8	)		(43	)		(84	)		(58	)
Net amounts recognized as expense	$	2		$	40		$	63		$	59

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Detailed Information Regarding Pension Benefits

The following information is based on October 10, 2007 and December 31, 2007, 2006 and 2005 measurement dates:

	Successor			Predecessor
	Period from October 11, 2007 through December 31,			Period From January 1, 2007 through October 10,			Year Ended December 31,
	2007			2007			2006			2005
Assumptions Used to Determine Net Periodic Pension Cost:
Discount rate		6.45	%		5.90	%		5.75	%		6.00	%
Expected return on plan assets		8.75	%		8.75	%		8.75	%		8.75	%
Rate of compensation increase		3.44	%		3.44	%		3.32	%		3.31	%
Components of Net Pension Cost:
Service cost	$	10		$	30		$	42		$	37
Interest cost		36			107			136			130
Expected return on assets		(47	)		(119	)		(147	)		(145	)
Amortization of prior service cost		—			1			3			3
Amortization of net loss		—			15			32			20
Recognized curtailment loss		—			—			—			1
Net periodic pension cost	$	(1	)	$	34		$	66		$	46
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net loss (gain)	$	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	)
Purchase accounting adjustment		—			49
Total recognized in other comprehensive income	$	20		$	(7	)
Total recognized in net periodic benefit cost and other comprehensive income	$	19		$	27
	Successor			Predecessor
	Period from October 11, 2007 through December 31,			Period From January 1, 2007 through October 10,			Year Ended December 31,
	2007			2007			2006			2005
Assumptions Used to Determine Benefit Obligations:
Discount rate		6.55	%		6.45	%		5.90	%		5.75	%
Rate of compensation increase		3.70	%		3.44	%		3.44	%		3.32	%

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	Successor			Predecessor
	Year Ended December 31, 2007			Year Ended December 31, 2006
Change in Pension Obligation:
Projected benefit obligation at beginning of year	$	2,457		$	2,440
Service cost		40			42
Interest cost		143			136
Plan amendments		—			2
Actuarial (gain) loss		(184	)		(47	)
Benefits paid		(121	)		(116	)
Settlements		—			—
Projected benefit obligation at end of year	$	2,335		$	2,457
Accumulated benefit obligation at end of year	$	2,219		$	2,297
Change in Plan Assets:
Fair value of assets at beginning of year	$	2,090		$	1,982
Actual return on assets		136			220
Employer contributions		4			4
Benefits paid		(122	)		(116	)
Settlements		—			—
Fair value of assets at end of year	$	2,108		$	2,090
Funded Status:
Projected pension benefit obligation	$	(2,335	)	$	(2,457	)
Fair value of assets		2,108			2,090
Funded status at end of year	$	(227	)	$	(367	)
	Successor			Predecessor
	Year Ended December 31, 2007			Year Ended December 31, 2006
Amounts Recognized in the Balance Sheet Consist of:
Other noncurrent assets (a)	$	9		$	9
Other current liabilities		(4	)		(2	)
Other noncurrent liabilities		(232	)		(374	)
Net liability recognized	$	(227	)	$	(367	)
Amounts Recognized in Accumulated Other Comprehensive Income under SFAS 158 Consist of:
Net loss	$	20		$	2
Prior service cost		—			5
Net amount recognized	$	20		$	7
Amounts Recognized as Regulatory Assets under SFAS 158 Consist of:
Net loss	$	65		$	203
Prior service cost		2			3
Net amount recognized	$	67		$	206

(a) Amounts represent overfunded plans.

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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		Predecessor
	December 31, 2007		December 31, 2006
Pension Plans with PBO and ABO in Excess Of Plan Assets:
Projected benefit obligations	$	2,330	$	2,452
Accumulated benefit obligation		2,214		2,291
Plan assets		2,094		2,076

Asset Allocations

The weighted-average asset allocations of pension plans by asset category are as follows:

	Successor		Predecessor		Target Allocation Ranges		Expected Long-Term Returns
Asset Type	Allocation of Plan Assets		Allocation of Plan Assets
	2007		2006
US equities	42.1	%	46.1	%	30%-65	%	8.9	%
International equities	20.0	%	18.6	%	5%-20	%	9.4	%
Fixed income	36.1	%	31.9	%	15%-50	%	6.4	%
Real estate	1.8	%	3.4	%	0%-10	%	8.6	%
	100.0	%	100.0	%			8.25	%

Detailed Information Regarding Postretirement Benefits Other Than Pensions

The following OPEB information is based on October 10, 2007 and December 31, 2007, 2006 and 2005 measurement dates:

	Successor			Predecessor
	Period from October 11, 2007 through December 31,			Period From January 1, 2007 through October 10,			Year Ended December 31,
	2007			2007			2006			2005
Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate		6.45	%		5.90	%		5.75	%		6.00	%
Expected return on plan assets		8.67	%		8.67	%		8.67	%		8.67	%
Components of Net Postretirement Benefit Cost:
Service cost	$	3		$	9		$	13		$	13
Interest cost		14			41			60			56
Expected return on assets		(6	)		(15	)		(21	)		(20	)
Amortization of net transition obligation		—			1			1			1
Amortization of prior service cost/(credit)		—			(2	)		(3	)		(3	)
Amortization of net loss		—			15			31			24
Net periodic pension cost	$	11		$	49		$	81		$	71
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net loss (gain)	$	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
Purchase accounting adjustment		—			13
						��
Total recognized in other comprehensive income	$	36		$	(2	)
Total recognized in net periodic benefit cost and other comprehensive income	$	47		$	47

164

	Successor	Predecessor
	Period from October 11, 2007 through December 31,	Period From January 1, 2007 through October 10,	Year Ended December 31,
	2007	2007	2006	2005
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate	6.55%	6.45%	5.90%	5.75%

	Successor			Predecessor
	Year Ended December 31, 2007			Year Ended December 31, 2006
Change in Postretirement Benefit Obligation:
Benefit obligation at beginning of year	$	948		$	1,065
Service cost		12			13
Interest cost		55			60
Participant contributions		17			14
Medicare Part D reimbursement		4			5
Actuarial (gain)/loss		(46	)		(150	)
Benefits paid		(62	)		(59	)
Benefit obligation at end of year	$	928		$	948
Change in Plan Assets:
Fair value of assets at beginning of year	$	251		$	245
Actual return on assets		10			23
Employer contributions		40			23
Participant contributions		17			14
Medicare Part D reimbursement		4			5
Benefits paid		(62	)		(59	)
Fair value of assets at end of year	$	260		$	251

165

	Successor			Predecessor
	Year Ended December 31, 2007			Year Ended December 31, 2006
Funded Status:
Benefit obligation	$	(928	)	$	(948	)
Fair value of assets		260			251
Funded status at end of year	$	(668	)	$	(697	)
Amounts Recognized in Accumulated Other Comprehensive Income under SFAS 158 Consist of:
Net loss	$	36		$	15
Prior service cost credit		—			(13	)
Net transition obligation		—			1
Net amount recognized	$	36		$	3
Amounts Recognized as Regulatory Assets under SFAS 158 Consist of:
Net loss	$	115		$	202
Prior service cost credit		(10	)		(12	)
Net transition obligation		6			8
Net amount recognized	$	111		$	198
The following tables provide information regarding the assumed health care cost trend rates.
	Successor			Predecessor
	December 31, 2007			December 31, 2006
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
Health care cost trend rate assumed for next year		7.95%			6.5%
Rate to which the cost trend is expected to decline (the ultimate trend rate)		5.00%			5.0%
Year that the rate reaches the ultimate trend rate		2013			2010
Assumed Health Care Cost Trend Rates-Medicare Eligible:
Health care cost trend rate assumed for next year		8.55%			8%
Rate to which the cost trend is expected to decline (the ultimate trend rate)		5.00%			5%
Year that the rate reaches the ultimate trend rate		2013			2012

	1-Percentage Point Increase	1-Percentage Point Decrease
Sensitivity Analysis of Assumed Health Care Cost Trend Rates:
Effect on accumulated postretirement obligation	$102	$(85)
Effect on postretirement benefits cost	8	(7)

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Asset Allocations –

The weighted average asset allocations of the OPEB plan by asset category are as follows:

Asset Type	Allocation of Plan Assets
	Successor		Predecessor
	December 31, 2007		December 31, 2006
US equities	52.6	%	56.8	%
International equities	10.3	%	9.3	%
Fixed income	36.2	%	32.2	%
Real estate	0.9	%	1.7	%
	100.0	%	100.0	%

Plan Type	Expected Long- Term Returns
401(h) accounts	8.25	%
Life Insurance VEBA	7.67	%
Union VEBA	7.67	%
Non-Union VEBA	5.00	%
Insurance Continuation Reserve	5.20	%
	7.90	%

Investment Strategy

The investment objective is to provide a competitive return on the assets in each plan, while at the same time preserving the value of those assets. The strategy is to invest a third of the assets in fixed income and two thirds in equity, while maintaining sufficient cash to pay benefits and expenses.

The fixed income assets are diversified by sector and security, are intermediate in duration, and maintain an average quality rating of at least “A” (as determined by a major ratings agency such as Moody’s). The allocation to fixed income assets also includes a small allocation to core income producing real estate through private, unlevered real estate investment trusts. The equity assets are diversified by size, style and location with a conservative bias toward value securities.

Expected Long-Term Rate of Return on Assets Assumption

EFH Corp. considered selected macroeconomic variables — such as inflation, output and monetary policy, and incorporated short-term market signals to base the transition from current levels to long-run equilibrium conditions. The macroeconomic variables along with several Treasury yield curve variables provide a core set of factors driving asset class returns. Bond returns were inferred directly from yield curve dynamics while equity and other asset class returns were derived from core macroeconomic and fixed income factors. 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 assumption for the portfolio.

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Assumed Discount Rate

In selecting the assumed discount rate, EFH Corp. considered fixed income security yields for an Aa rated portfolio of bonds as reported by Moody’s.

Amortization in 2008

In 2008, EFH Corp. will have no amortization of the estimated net loss and prior service cost for the defined benefit pension plans and no amortization of the estimated net loss, prior service credit and net transition obligation for the OPEB plans from accumulated other comprehensive income into net periodic benefit cost. This accounting is the result of EFH Corp. being within the SFAS 158 10% range in which amortization of accumulated other comprehensive income is not required until the accumulated other comprehensive income balance exceeds 10% of the benefit obligation.

Contributions in 2008

Estimated funding for calendar year 2008 totals $155 million for the Retirement Plan and $49 million for the OPEB plan.

Future Benefit Payments

Estimated future benefit payments to beneficiaries are as follows:

	Successor
	2008			2009			2010			2011			2012			2013-17
Pension benefits	$	121		$	126		$	132		$	138		$	147		$	1,010
OPEBs	$	59		$	61		$	65		$	67		$	71		$	395
Medicare Part D subsidies received	$	(6	)	$	(6	)	$	(7	)	$	(7	)	$	(8	)	$	(47	)

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 the 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 the 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 19 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 connection with the Merger, 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, officer or qualified managerial employees of EFH Corp. or its subsidiaries or affiliates in the form of non-qualified stock options, stock appreciation rights, restricted 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, canceled, 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 19.5 million shares of EFH Corp. common stock were issued to certain management employees in December 2007. The options provide the holder the right to purchase EFH Corp. common stock for $5.00 per share, which was the fair market value at grant date. 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.

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.

Assumptions	Time-Based Options	Performance-Based Options
Expected volatility	30%	30%
Expected annual dividend	—	—
Expected life (in years)	6.4	5.4—7.4
Risk-free rate	3.81%	3.92%

The weighted average grant-date fair value of the Time-Based Options granted in December 2007 was $1.92 per option. The grant-date fair value of the Performance-Based Options granted in December 2007 ranged from $1.74 to $2.09 depending upon the performance period.

Compensation expense for Time-Based and Performance-Based Options is based on the grant-date fair value and recognized over the vesting period as employees perform services. Less than $100,000 was recognized during the 2007 Successor period for Time-Based Options, essentially all to expense. EFH Corp. has applied a forfeiture assumption of 5% per annum in the calculation of such expense.

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As of December 31, 2007, there was approximately $17.7 million of unrecognized compensation expense related to nonvested Time-Based Options, which is expected to be recognized ratably over a weighted-average period of approximately 5 years.

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

	Time-Based					Performance-Based
Options	Shares (millions)	Weighted Average Exercise Price		Aggregate Intrinsic Value (millions)		Shares (millions)	Weighted Average Exercise Price		Aggregate Intrinsic Value (millions)
Outstanding at October 11, 2007	—	$	—	$	—	—	$	—	$	—
Granted	9.8		5.00		—	9.8		5.00		—
Exercised	—		—		—	—		—		—
Forfeited	—		—		—	—		—		—
Outstanding at December 31, 2007 (weighted average remaining term of 10 years)	9.8		5.00		—	9.8		5.00		—
Exercisable at December 31, 2007	—		—		—	—		—		—
Expected to vest at December 31, 2007 (weighted average remaining term of 10 years)	9.3		5.00		—	9.3		5.00		—

Compensation expense for Performance-Based Options is 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. 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. 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. EFH Corp. will apply a forfeiture assumption of 5% per annum in the calculation of such expense.

As of December 31, 2007, there was approximately $17.8 million of unrecognized compensation expense related to nonvested Performance-Based Options, which EFH Corp. could record as an expense over a weighted-average period of approximately 5 years, subject to the achievement of financial performance being probable.

Share based payments expense related to non-employees in the 2007 Successor period totaled approximately $1 million.

As of December 31, 2007, certain members of executive management had agreed to forego receipt of payment of an aggregate of approximately $9 million of equity awards to which they were entitled at the closing of the Merger, in exchange for deferred common shares of EFH Corp. under the terms of deferred share agreements.

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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 2005 and 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 for 2005 awards and the S&P 500 Electric Utilities Index and S&P 500 Multi-Utilities Index for 2006 awards (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.

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 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

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Assumptions	Period from January 1, 2007 Through October 10, 2007	2006	2005
Expected volatility	29% -30%	29%	25%-30%
Expected annual dividend	-	$1.65	$1.125
Risk-free rate	4.8% -4.9%	4.83%	5.75%
Discount for liquidity restrictions	0% -4.8%	6.4%-11.1%	6.5% - 12.5%

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.

The following table presents information about Predecessor stock-based compensation plans.

	Performance Unit Awards			Stock Options under TXU Gas Plan
Number of awards:
Balance — December 31, 2004		6,274,562		5,272
Granted in 2005		1,231,392		—
Forfeited/expired		(687,940	)	(1,520	)
Vested/exercised		(1,532,032	)	(2,232	)
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
2005	$	20.68
2006	$	42.35
Period from January 1, 2007 to
October 10, 2007	$	67.08

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The table above reflects the weighted average fair value of the awards on grant date.

Reported expense related to the awards totaled $27 million, $27 million and $32 million ($18 million, $18 million and $21 million after-tax) in the period from January 1, 2007 through October 10, 2007, 2006 and 2005, respectively. 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, 2006 and 2005 totaled $613 million, $210 million and $120 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.

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. 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 a quoted 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. The adoption of SFAS 157 reflects the application of FSP 157-2, “Effective Date of FASB Statement No. 157”, which was issued by the FASB in February 2008 and delays until financial statements issued after December 15, 2008 the effective date of SFAS 157 for all nonfinancial assets and liabilities, except for those recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).

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 for which the exchange traded pricing is actively quoted.

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• 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 best information available from the market combined with its own internally developed valuation methodologies to develop its best estimate of fair value. For example, certain derivatives 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. 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.

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At December 31, 2007, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3		Netting (a)			Total
Assets:
Commodity-related contracts	$	767	$	683	$	148	$	(1,253	)	$	345
Interest rate swaps		—		8		—		—			8
Nuclear decommissioning trust (b)		165		319		—		—			484
Salary deferral plan investments (b)		31		70		—		—			101
Total assets	$	963	$	1,080	$	148	$	(1,253	)	$	938
Liabilities:
Commodity-related contracts	$	815	$	2,372	$	321	$	(1,253	)	$	2,255
Interest rate swaps		—		324		—		—			324
Total liabilities	$	815	$	2,696	$	321	$	(1,253	)	$	2,579

(a) Represents the effects of netting assets and liabilities at the counterparty agreement level where the legal right of offset exits.

(b) The nuclear decommissioning trust and salary deferral plan investments are included in the Investments line on the balance sheet.

Commodity-related contracts primarily represent mark-to-market values of natural gas and electricity derivative instruments that have not been designated “normal” purchases or sales under SFAS 133.

Interest rate swaps consist almost entirely of variable-to-fixed rate swap instruments that have been designated as cash flow hedges.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

Salary deferral plan assets represent securities held for the purpose of funding the liabilities of EFH Corp.’s Salary Deferral Program. These investments include life insurance contracts, equity, debt and other fixed-income securities.

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The following table presents the changes in fair value of EFH Corp.’s Level 3 assets and liabilities for the year ended December 31, 2007:

	Commodity- related contracts
Balance at October 11, 2007 (net liability)	$	(133	)
Total realized and unrealized gains (losses) (a):
Included in net income (loss)		(117	)
Included in other comprehensive income (loss)		7
Purchases, sales, issuances and settlements (net) (b)		28
Net transfers in and/or out of Level 3 (c)		42
Balance at December 31, 2007 (net liability)	$	(173	)
Net change in unrealized gains (losses) included in net income relating to instruments held at December 31, 2007 (a)	$	(101	)

(a) Changes in values of commodity-related contracts are largely reported in operating revenues; certain of such contracts are accounted for as cash flow hedges for which changes in values are reported as other comprehensive income to the extent the hedges are effective and in operating revenues for the ineffective portion.

(b) Settlements represent amounts included in the beginning balance for the period.

(c) Includes transfers due to changes in the observability of significant inputs. Amounts transferred in and/or out represent December 31, 2007 values.

25.     FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of significant nonderivative financial instruments were as follows:

	Successor						Predecessor
	December 31, 2007						December 31, 2006
	Carrying Amount			Fair Value (a)			Carrying Amount			Fair Value
On balance sheet assets (liabilities):
Long-term debt (including current maturities) (b)	$	(38,955	)	$	(38,896	)	$	(11,018	)	$	(11,308	)
LESOP note receivable (see Note 19)	$	—		$	—		$	210		$	242
Off balance sheet assets (liabilities):
Financial guarantees	$	—		$	(1	)	$	—		$	(6	)

(a) Fair value determined in accordance with SFAS 157.

(b) Excludes capital leases.

See Note 20 for discussion of accounting for financial instruments that are derivatives.

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Predecessor Information

The fair values of on-balance sheet instruments were estimated at the lesser of either the call price or the market value as determined by quoted market prices, where available, or, where not available, at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risk. The fair value of each financial guarantee was based on the difference between the credit spread of the entity responsible for the underlying obligation and a financial counterparty applied, on a net present value basis, to the notional amount of the guarantee. The carrying amounts for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximated fair value due to the short maturity of such instruments. The fair values of other financial instruments, including the Capgemini put option, for which carrying amounts and fair values have not been presented, were not materially different than their related carrying amounts.

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. EFH Corp. paid $8 million under terms of the Management Agreement to the Sponsor Group in the period from October 11, 2007 to December 31, 2007. 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. In November and December 2007, EFH Corp. and TCEH offered the EFH Corp. Notes and the TCEH Notes, respectively. Affiliates of GS Capital Partners served as initial purchasers in such offerings. 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.

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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, retail electricity sales to residential and business customers, wholesale energy sales and purchases, commodity risk management and trading activities as well as the development and construction of new generation facilities, 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 canceled 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 for a third party 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. 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.

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	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007
							Year Ended December 31,
							2006			2005
Operating Revenues
Competitive Electric	$	179		$	6,330		$	9,549		$	9,552
Regulated Delivery		532			1,987			2,449			2,394
Corp. and Other		11			37			49			30
Eliminations		(220	)		(864	)		(1,191	)		(1,314	)
Consolidated		502			7,490			10,856			10,662
Regulated Revenues — Included in Operating Revenues
Competitive Electric		—			—			—			—
Regulated Delivery		532			1,987			2,449			2,394
Corp. and Other		—			—			—			—
Eliminations		(208	)		(824	)		(1,139	)		(1,278	)
Consolidated		324			1,163			1,310			1,116
Affiliated Revenues — Included in Operating Revenues
Competitive Electric		2			5			8			9
Regulated Delivery		208			824			1,139			1,278
Corp. and Other		10			35			44			27
Eliminations		(220	)		(864	)		(1,191	)		(1,314	)
Consolidated		—			—			—			—
Depreciation and Amortization
Competitive Electric		315			253			334			313
Regulated Delivery		96			366			476			446
Corp. and Other		4			15			20			17
Eliminations		—			—			—			—
Consolidated		415			634			830			776
Equity in Earnings (Losses) of Unconsolidated Subsidiaries
Competitive Electric		(2	)		(5	)		(10	)		(7	)
Regulated Delivery		(1	)		(2	)		(4	)		(3	)
Corp. and Other		(1	)		(4	)		(19	)		(1	)
Eliminations		4			10			19			11
Consolidated		—			(1	)		(14	)		—
Interest Income
Competitive Electric		10			271			202			70
Regulated Delivery		12			44			58			59
Corp. and Other		42			106			91			99
Eliminations		(40	)		(365	)		(305	)		(180	)
Consolidated		24			56			46			48
Interest Expense and Related Charges
Competitive Electric		609			357			388			393
Regulated Delivery		70			242			286			269
Corp. and Other		200			437			461			320
Eliminations		(40	)		(365	)		(305	)		(180	)
Consolidated		839			671			830			802
Income Tax Expense (Benefit)
Competitive Electric		(656	)		306			1,239			687
Regulated Delivery		30			160			170			174
Corp. and Other		(47	)		(157	)		(146	)		(229	)
Eliminations		—			—			—			—
Consolidated		(673	)		309			1,263			632

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	Successor		Predecessor
	Period from October 11, 2007 through December 31, 2007		Period From January 1, 2007 through October 10, 2007		Year Ended December 31,
					2006		2005
Income (loss) from Continuing Operations Before Extraordinary Items and Cumulative Effect of Changes in Accounting Principles
Competitive Electric	(1,245	)	722		2,363		1,429
Regulated Delivery	63		265		344		351
Corp. and Other	(179	)	(288	)	(242	)	(5	)
Eliminations	—		—		—		—
Consolidated	(1,361	)	699		2,465		1,775
Investment in Equity Investees
Competitive Electric	(1	)			—		—
Regulated Delivery	—				—		—
Corp. and Other	—				1		—
Eliminations	—				—		—
Consolidated	(1	)			1		—
Total assets (a)
Competitive Electric	48,277				18,906		17,885
Regulated Delivery	15,458				10,709		9,911
Corp. and Other	2,992				1,676		1,717
Eliminations	(2,943	)			(5,458	)	(3,974	)
Consolidated	63,784				25,833		25,539
Capital Expenditures
Competitive Electric	530		1,901		1,330		309
Regulated Delivery	153		555		840		733
Corp. and Other	1		7		10		5
Eliminations	—		—		—		—
Consolidated	684		2,463		2,180		1,047

(a) Assets by segment exclude investments in affiliates.

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28.     SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31,
							2006			2005
Operating revenues
Regulated	$	532		$	1,987		$	2,449		$	2,394
Unregulated		190			6,367			9,598			9,582
Intercompany sales eliminations — regulated		(208	)		(824	)		(1,139	)		(1,278	)
Intercompany sales eliminations — unregulated		(12	)		(40	)		(52	)		(36	)
Total operating revenues		502			7,490			10,856			10,662
Costs and operating expenses
Fuel, purchased power and delivery fees — unregulated (a)		644			2,381			2,784			4,261
Operating costs — regulated		182			637			770			758
Operating costs — unregulated		124			470			603			667
Depreciation and amortization — regulated		96			366			476			446
Depreciation and amortization — unregulated		319			268			354			330
Selling, general and administrative expenses — regulated		45			134			172			198
Selling, general and administrative expenses — unregulated		171			557			647			583
Franchise and revenue-based taxes — regulated		62			198			262			247
Franchise and revenue-based taxes — unregulated		31			84			128			117
Other income		(14	)		(69	)		(121	)		(151	)
Other deductions		61			841			269			45
Interest income		(24	)		(56	)		(46	)		(48	)
Interest expense and other charges		839			671			830			802
Total costs and expenses		2,536			6,482			7,128			8,255
Income (loss) from continuing operations before income taxes, extraordinary gain (loss) and cumulative effect of changes in accounting principles	$	(2,034	)	$	1,008		$	3,728		$	2,407

(a) Includes unregulated cost of fuel consumed of $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, $927 million in 2006 and $968 million in 2005. 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.

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Interest Expense and Related Charges

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007
							Year Ended December 31,
							2006			2005
Interest	$	800		$	732		$	861		$	798
Preferred stock dividends of subsidiaries		—			—			—			3
Amortization of debt fair value discount resulting from purchase accounting		17			—			—			—
Amortization of debt issuance cost, discounts and premiums		81			19			16			18
Capitalized interest, primarily related to generation facility and regulated utility asset construction		(59	)		(80	)		(47	)		(17	)
Total interest expense and related charges	$	839		$	671		$	830		$	802

Restricted Cash

	Successor				Predecessor
	At December 31, 2007				At December 31, 2006
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to TCEH’s senior secured letter of credit facility (See Note 17)	$	—	$	1,250	$	—	$	—
Pollution control revenue bond funds held by trustee (See Note 17)		—		29		—		241
Amounts related to securitization (transition) bonds		56		17		55		17
All other		—		—		3		—
Total restricted cash	$	56	$	1,296	$	58	$	258

Inventories by Major Category

	Successor		Predecessor
	December 31, 2007		December 31, 2006
Materials and supplies	$	174	$	189
Fuel stock		138		94
Natural gas in storage		93		75
Environmental energy credits and emission allowances (a)		—		25
Total inventories	$	405	$	383

(a) The Successor reports environmental energy credits and emission allowances as intangible assets. See Note 3.

182

Property, Plant and Equipment

	Successor		Predecessor
	December 31,		December 31,
	2007		2006
Competitive Electric:
Generation and mining	$	17,069	$	16,302
Nuclear fuel (net of accumulated amortization of $47 and $1,123)		451		159
Other assets		22		35
Regulated Delivery:
Transmission		3,388		3,179
Distribution		8,036		7,788
Other assets		106		137
Corporate and Other		124		134
Total		29,196		27,734
Less accumulated depreciation		4,076		10,905
Net of accumulated depreciation		25,120		16,829
Construction work in progress:
Competitive Electric		3,358		1,607
Regulated Delivery		170		123
Corporate and Other		2		10
Total construction work in progress		3,530		1,740
Property, plant and equipment — net	$	28,650	$	18,569

Assets related to capitalized leases included above totaled $161 million at December 31, 2007 and $96 million at December 31, 2006, net of accumulated depreciation.

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.

183

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, 2007 and 2006:

Asset retirement liability at January 1, 2006	$	558
Additions:
Accretion		36
Incremental mining reclamation costs		21
Reductions:
Net change in mining land reclamation estimated liability		(4	)
Mining reclamation		(26	)
Asset retirement liability at December 31, 2006	$	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

Regulatory Assets and Liabilities

	Successor		Predecessor
	December 31, 2007		December 31, 2006
Regulatory assets
Generation-related regulatory assets securitized by transition bonds	$	967	$	1,316
Employee retirement costs		265		461
Storm-related service recovery (self insurance reserve) costs		149		138
Securities reacquisition costs		105		112
Recoverable deferred income taxes — net		84		90
Employee severance costs		20		43
Other		3		1
Total regulatory assets		1,593		2,161
Regulatory liabilities
Credit due REPs under PUCT stipulation		72		—
Committed spending for demand side management initiatives		100		—
Investment tax credit and protected excess deferred taxes		55		63
Over-collection of securitization (transition) bond revenues		34		34
Nuclear decommissioning cost over-recovery		13		17
Other regulatory liabilities		14		19
Total regulatory liabilities		288		133
Net regulatory assets	$	1,305	$	2,028

184

Regulatory assets that have been reviewed and approved by the PUCT and are not earning a return totaled $997 million and $1.3 billion at December 31, 2007 and 2006, respectively, including the generation-related regulatory assets securitized by transition bonds that have a remaining recovery period of nine years. As part of purchase accounting, the carrying value of the generation-related regulatory assets was reduced by $213 million, and this amount will be accreted to other income over the remaining nine-year recovery period. See Note 10 for discussion of effects on regulatory assets and liabilities of the stipulation approved by the PUCT.

Other regulatory assets totaling $446 million have not been reviewed by the PUCT but are deemed by management to be probable of recovery.

Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:

	Successor		Predecessor
	December 31, 2007		December 31, 2006
Unfavorable purchase and sales contracts	$	751	$	—
Uncertain tax positions (including accrued interest)		1,939		968
Asset retirement obligations		773		583
Retirement plan and other employee benefits		1,076		1,251
Other		111		385
Total other noncurrent liabilities and deferred credits	$	4,650	$	3,187

Unfavorable Purchase and Sales Contracts — Unfavorable purchase and sales contracts primarily represent the out-of-the-money value of 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 out-of-the-money value as of October 10, 2007 as a deferred credit. Amortization of the deferred credit related to unfavorable contracts is based on the terms of the contract and recorded as revenues or a reduction of purchased power costs as appropriate. The amortization amount totaled $5 million in the 2007 Successor period and was recorded in the results of the Competitive Electric segment. 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, 2007 is as follows:

	Successor
Year	Amount
2008	$	26
2009		25
2010		24
2011		24
2012		24

185

Supplemental Cash Flow Information

	Successor		Predecessor
	Period from October 11, 2007 through December 31, 2007		Period From January 1, 2007 through October 10, 2007		Year Ended December 31,
					2006		2005
Cash payments (receipts) related to continuing operations:
Interest (net of amounts capitalized)	$	437	$	594	$	823	$	774
Income taxes		—		271		220		89
Cash payments (receipts) related to discontinued operations:
Income taxes		—		—		—		30
Noncash investing and financing activities:
Out-of-the-money values of power sales agreements (see Note Z)		—		264		—		—
Noncash construction expenditures (a)		211		210		228		61
Note issued in acquisition of mining property		—		65		—		—
Generation plant rail spur capital lease		—		52		—		95
Noncash capital contribution from Texas Holdings		23		—		—		—
Consolidation of lease trust:
Increase in assets		—		—		—		35
Increase in debt		—		—		—		96

(a) Represents end-of-period accruals.

See Note 6 for the effects of adopting FIN 47 which were noncash in nature.

186

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

None.

Item 9A(T). 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, 2007. 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.

187

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, 2007 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, 2007 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/ DAVID A. CAMPBELL
John F. Young, President and	David A. Campbell, Executive Vice President
Chief Executive Officer	and Chief Financial Officer
March 31, 2008

188

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. (formerly TXU Corp.) and subsidiaries (the “Company”) as of December 31, 2007 based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’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 the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

189

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of December 31, 2007 (successor) and for the period from October 11, 2007 through December 31, 2007 (successor) and for the period from January 1, 2007 through October 10, 2007 (predecessor) of the Company and our report dated March 31, 2008 expressed an unqualified opinion on those financial statements and financial statement schedule and included an explanatory paragraph regarding the completion of the Company’s merger with Texas Energy Future Merger Sub Corp and becoming a subsidiary of Texas Energy Future Holdings Limited Partnership on October 10, 2007.

/s/ Deloitte & Touche LLP

Dallas, Texas

March 31, 2008

190

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
David Bonderman	65	2007	David Bonderman is a founding partner of TPG Capital (“TPG”). Before forming TPG in 1992, Mr. Bonderman was Chief Operating Officer of the Robert M. Bass Group in Fort Worth, Texas. He serves on the boards of the following public companies: Burger King Holdings, Inc., CoStar Group, Inc., Gemalto N.V., and RyanAir Holdings PLC, of which he is Chairman.
Donald L. Evans (1)(2)(3)(4)	61	2007	Donald L. Evans has been Non-Executive Chairman of EFH Corp. since October 2007 and CEO of the Financial Services Forum since 2005, 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.
Frederick M. Goltz (2)(3)	37	2007	Frederick M. Goltz has been with Kohlberg Kravis Roberts and Co., L.P. (“KKR”) for 10 years. Mr. Goltz is one of the heads of KKR’s Energy and Natural Resources industry team and leads KKR’s efforts in the natural resources sector. He is a director of EFC Holdings, TCEH, and Luminant.
James R. Huffines (1)(3)	57	2007	James R. Huffines 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. He also serves on the Board of Capstar Acquisition Corporation.
Scott Lebovitz	32	2007	Scott Lebovitz 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.

191

Name	Age	Served As Director Since	Business Experience
Jeffrey Liaw (1)	31	2007	Jeffrey Liaw is active in TPG’s Energy and Industrial investing practice areas. Before joining TPG in 2005, he worked for Bain Capital in their Industrials practice since 2003. Mr. Liaw serves on the boards of both public and private companies including Graphic Packaging Corporation and Oncor.
Marc S. Lipschultz (2)(4)	39	2007	Marc S. Lipschultz has been with KKR for 12 years. He is one of the heads of KKR’s Energy and Natural Resources industry team and leads KKR���s efforts in the power sector. Currently, he is a director of Accel-KKR Company and Oncor.
Michael MacDougall (2)(3)	37	2007	Michael MacDougall 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.
Lyndon L. Olson, Jr. (3)	61	2007	Lyndon L. Olson, Jr. has been a Senior Advisor with Citigroup Inc. since 2002, 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)	37	2007	Kenneth Pontarelli 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., NextMedia Investors, L.L.C, and TXU Energy.

192

Name	Age	Served As Director Since	Business Experience
William K. Reilly	68	2007	William K. Reilly is a Senior Advisor to TPG and a founding partner of Aqua International Partners, an investment group that invests in companies that serve the water and renewable energy sectors, having previously served as the seventh Administrator of the 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)	35	2007	Jonathan D. Smidt 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)	51	2008	John F. Young was elected President and Chief Executive of EFH Corp. in 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.
William J. Young	43	2007	William Young is Co-Head of the Goldman Sachs Infrastructure Investment Group. Mr. Young joined Goldman Sachs in 2001 as a Managing Director and Co-Head of the European Structured and Principal Finance Group. In 2002, Mr. Young was promoted to a Partner in the Financing Group, which includes all debt, derivative and equity capital markets activities for the firm. Mr. Young became Co-Head of the Corporate and Acquisition Finance Group, which included the structured and leveraged finance businesses. Prior to joining Goldman Sachs, Mr. Young was with Citibank for 16 years, working in the Leveraged Finance and Work-Out Group and most recently running its European Securitisation Group.

193

Name	Age	Served As Director Since	Business Experience
Kneeland Youngblood (1)	52	2007	Kneeland Youngblood 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. Dr. Youngblood is chairman of the American Beacon Funds, a $30 billion mutual fund company, managed by American Beacon Advisors, a $65 billion investment affiliate of American Airlines. He is a director of the following public companies: Starwood Hotels and Resorts Worldwide, Inc., Gap Inc. and Burger King Holdings, Inc. Dr. 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

194

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	51	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 a number of 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.
James A. Burke	39	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	39	Executive Vice President and Chief Financial Officer of EFH Corp.	April 2007	David A. Campbell was elected Executive Vice President of EFH Corp. in May 2004 and Chief Financial Officer in April 2007, having served as Acting Chief Financial Officer since March 2006. Prior to joining EFH Corp. in 2004, Mr. Campbell was a Principal of McKinsey & Company, Inc.
M. Rizwan Chand	44	Senior Vice President of EFH Corp.	August 2005	M. Rizwan Chand was elected Senior Vice President of EFH Corp. in August 2005. Prior to joining EFH Corp. in 2005, Mr. Chand was Vice President of Human Resources and Corporate Relations for Kennametal, Inc.
Charles R. Enze	54	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.

195

Name of Officer	Age	Positions and Offices Presently Held	Date First Elected to Present Offices	Business Experience (Preceding Five Years)
M. S. Greene	62	President and Chief Executive of Luminant	October 2007	M. S. Greene was elected President and Chief Executive of Luminant in October 2007 and TCEH in July 2005. Previously Mr. Greene held several other offices including 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.
Michael T. McCall	50	Executive Vice President and Chief Operating Officer of Luminant	January 2008	Michael T. McCall was elected Executive Vice President and Chief Operating Officer of Luminant in January 2008. Previously Mr. McCall held several other offices including Chairman of the Board, President and Chief Executive of Luminant Energy, Senior Vice President of TXU Power, President of TXU Gas and Vice President of EFH Corporate Services Company.
David P. Poole	45	Executive Vice President of EFH Corp.	March 2006	David P. Poole was elected Executive Vice President of EFH Corp. in March 2006 and was also General Counsel of EFH Corp. from March 2006 through March 2008. Previously, Mr. Poole held several other subsidiary offices including Senior Vice President and Chief Legal Officer of TXU Power, Senior Vice President of EFH Corp., Senior Vice President of EFH Corporate Services Company, and Vice President and Associate General Counsel of EFH Corporate Services Company. Prior to joining EFH Corp. in 2004, Mr. Poole was Managing Partner of the Dallas office of Hunton & Williams LLP.
Jonathan A. Siegler	35	Senior Vice President of Strategy, Mergers and Acquisitions of EFH Corporate Services Company	February 2007	Jonathan A. Siegler was elected Senior Vice President of Strategy, Mergers and Acquisitions of EFH Corporate Services Company in February 2007. Previously Mr. Siegler was Vice President of EFH Corporate Services Company. Prior to joining EFH Corp. in 2004, Mr. Siegler was Engagement Manager for McKinsey & Company.
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.

196

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.

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.

Section 16(a) Beneficial Ownership Reporting Compliance

Prior to the Merger, Section 16(a) of the Securities Exchange Act of 1934 required EFH Corp.’s directors and executive officers to file with the SEC reports of ownership and changes in ownership with respect to the equity securities of EFH Corp. Based solely on a review of the copies of the reports furnished to EFH Corp. and written representations that no other reports were required, during 2007, all required reports were timely filed, except that, as the result of an inadvertent oversight, Messrs. T. L. Baker, M. S. Greene and Michael T. McCall were late filing reports disclosing the disposition of 877, 4,952, and 2,816 stock units, respectively, representing the maturity of exercisable derivative securities under the TXU Deferred and Incentive Compensation Plan.

197

Item 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Overview

On October 10, 2007, Texas Energy Future Merger Sub Corp. merged with and into Energy Future Holdings Corp. (formerly named TXU Corp. and referred to herein as “we,” “us,” the “company” or “EFH Corp.”) (the “Merger”). As a result of the Merger, investment funds associated with or designated by Kohlberg Kravis Roberts & Co., TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman, Sachs & Co. (the “Sponsor Group”), and certain other co-investors (together with the Sponsor Group, the “Investors”), including affiliates of Citigroup Global Markets Inc., Morgan Stanley & Co. Incorporated and LB I Group, indirectly own over 90% of our issued and outstanding common stock, no par value, through their investment in Texas Energy Future Holdings Limited Partnership (“Texas Holdings”). Prior to the completion of the Merger, our executive compensation programs were determined and assessed by our Organization and Compensation Committee as it was constituted prior to the Merger (the “Pre-Merger O&C Committee”). The Pre-Merger O&C Committee was composed of five non-employee, independent directors, each of whom satisfied the requirements for independence under applicable law and regulations. Our Board of Directors (“Board”) has constituted a new Organization and Compensation Committee that establishes and assesses our executive compensation programs (the “O&C Committee”). The O&C Committee is comprised of three non-employee directors. For an interim period subsequent to the Merger and prior to the O&C Committee being constituted certain executive compensation determinations were made by management of the Sponsor Group. All such determinations have been subsequently approved by the O&C Committee or the Board.

As a result of the Merger and the fact that we have a new Board and O&C Committee, in preparing this Compensation Discussion and Analysis we have largely focused on describing our current compensation structure and philosophy and the effects of the Merger on the compensation of our executive officers. We only discuss pre-Merger compensation matters to the extent that we believe they are material to our current set of investors. For a more detailed discussion of our compensation structure and philosophy with respect to the pre-Merger time period, we refer you to our proxy statement filed with the Securities and Exchange Commission (“SEC”) on July 25, 2007 (the “Merger Proxy”).

Similar to the responsibilities the Pre-Merger O&C Committee had prior to the Merger, the responsibilities of the O&C Committee include:

• determining and overseeing executive compensation programs, 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 CEO 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 on page 215 (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 in this regard. The O&C Committee and the CEO then review the CEO’s assessments of the executive officers and, in that context, the O&C Committee approves the executive officers’ compensation.

Our Pre-Merger O&C Committee used from time to time, and our current O&C Committee may use from time to time, independent compensation consultants to advise on executive compensation issues, including salary surveys, performance measurement selection and peer group selection. Prior to the Merger, we assessed our compensation program against other publicly-traded utility, energy and industrial companies, utilizing a variety of market reference points and benchmarks, median competitive data, performance measurements and peer group selection. For information related to market reference points and peer groups used by our Pre-Merger O&C Committee, please refer to the Merger Proxy. We expect to continue to assess our compensation programs in a manner consistent with our pre-Merger practices; in addition, as a privately-held company, we will also assess our compensation program against other privately-held companies and use compensation practices that are used by privately-held companies. We do not currently benchmark the compensation of our Named Executive Officers to a particular peer group and no executive compensation surveys were conducted in connection with the executive compensation changes that followed the Merger.

198

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 and by giving our executive officers an opportunity to invest in our common stock. Equity ownership, coupled with other long-term incentives, has been and will continue to be 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

• in addition to linking an executive officer’s compensation to overall corporate performance, 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 the company by:

• aligning performance measures with our business objectives to drive the financial and operational performance of our company and 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;

• strengthening the correlation between the long-term interests of our executive officers and the interests of stockholders through equity compensation and investment opportunities; and

• phasing out or eliminating perquisites and programs that do not support our business objectives or fit within our corporate culture.

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 Energy Future Holdings Corp. and Affiliates (the “2007 Stock Incentive Plan”);

• the opportunity to participate in our Salary Deferral Program and our Thrift 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 businesses, to persons employed by us at the time of the Merger).

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In addition, our Named Executive Officers are expected to make a minimum level of investment in our common stock prior to receiving any Stock Option Awards. We believe this upfront investment further aligns the interests of our Named Executive Officers and stockholders and demonstrates their long-term commitment to our company. We refer to this minimum investment program as the Management Investment Opportunity.

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 as well as business unit operational targets (including productivity, reliability 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.

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.

Consistent with previous practice, the O&C Committee will review 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.

Prior to the Merger, base salaries had generally been held flat since October 2004, when the company was at the beginning stages of a turnaround phase of its business strategy and compensation focused largely on long-term shareholder value creation. Following the Merger, base salary increases were offered to, and made effective for, certain of our executive officers who agreed, at that time, to stay on with us as a privately-held company. These executive officers are in key leadership roles within our business units and are critical for us to continue to achieve strong operational performance. These salary increases also took into account the following:

• Messrs. Greene and McCall were promoted to take on significantly larger roles within the organization. Mr. Greene was promoted from CEO of Luminant Power to CEO of its parent, Luminant, while Mr. McCall was promoted from head of Luminant Energy to Chief Operating Officer of Luminant. Both promotions come with substantially increased responsibilities because Luminant includes the Luminant Power generation business, the Luminant Construction generation development business and the Luminant Energy wholesale energy trading and commodity risk management business;

• Mr. Burke’s salary had been frozen since he joined the company as a senior vice president in 2004. He did not get an increase in salary when he was promoted to the CEO of TXU Energy in August 2005. The post-Merger increase was provided, in part, to bring his cash compensation to what we believe is a market-competitive level for his position as CEO of TXU Energy;

• Many of our employees, including these executive officers, will have greater responsibilities resulting from the new business model for our business units; and

• We want to ensure cash compensation is competitive and sufficient to entice these key operating executive officers to remain with us, now as a privately-held company, recognizing the higher performance expectations of the new owners (across a broad set of operational, financial, customer service and community-oriented goals and objectives) and higher risk levels associated with being a highly leveraged company.

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2007 Base Salary for Energy Future Holdings Corp.’s Named Executive Officers

Name	Title	Salary prior to Merger		Salary post Merger
M. S. Greene	CEO of Luminant	$	507,000	$	650,000
David A. Campbell (1)	Executive Vice President and Chief Financial Officer of EFH Corp.	$	382,000	$	382,000
David P. Poole (2)	Executive Vice President and former General Counsel of EFH Corp.	$	307,000	$	307,000
Michael T. McCall	Chief Operating Officer of Luminant	$	325,000	$	500,000
James A. Burke	CEO of TXU Energy	$	275,000	$	600,000
C. John Wilder (3)	Former CEO of EFH Corp.	$	1,250,000		N/A
T. L. Baker (3)	Chairman Emeritus of EFH Corp.	$	632,000		N/A

(1) Mr. Campbell’s base salary has not changed since October 2004.

(2) Mr. Poole’s base salary was not changed immediately after the Merger as he was not expected to remain with us except through a transitional period. In order to incent Mr. Poole to remain with us through a transitional period, on January 2, 2008, we increased Mr. Poole’s base salary to the rate of $66,666 per month. Mr. Poole left the company on March 31, 2008. He resigned as General Counsel on March 24, 2008 when Mr. Robert C. Walters was hired to serve as our General Counsel.

(3) Mr. Wilder resigned effective with the closing of the Merger and Mr. Baker retired in November 2007. Because Mr. Baker’s retirement was expected at the time of the Merger, we did not change his base salary after the Merger.

Executive Annual Incentive Plan

The Executive Annual Incentive Plan provides an annual performance-based cash bonus for the successful attainment of certain annual operational, financial, customer service and community-oriented goals that are established at each of the corporate, business unit and individual levels by the O&C Committee at the beginning of each year. Under the terms of the plan, the performance targets established by the O&C Committee must be met before awards under the plan are paid. 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 and business unit funding percentages are aggregated and 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 applied to the calculated award to determine the final incentive payment. 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 maximum award any participant can receive under the Executive Annual Incentive Plan is four times their target incentive level; however, 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 2007 annual incentive targets (pro-rated for pre- and post-Merger target compensation) for each Named Executive Officer.

2007 Annual Incentives for Our Named Executive Officers

Name	Pre-Merger Target Payout (% of Salary)	Post-Merger Target (% of salary) (1)	Target Award ($ Value)		Actual Award (2)		Actual Award (percentage of Target)
M. S. Greene (3)	60%	75%	$	350,025	$	384,065	110%
David A. Campbell (4)	60%	60%	$	229,200	$	300,481	131%
David P. Poole (5)	60%	60%	$	184,200	$	220,487	120%
Michael T. McCall (6)	60%	75%	$	240,000	$	145,800	61%
James A. Burke (7)	60%	75%	$	236,250	$	274,050	116%
C. John Wilder (8)	200%	N/A	$	2,083,333	$	2,083,333	100%
T. L. Baker (9)	60%	N/A	$	316,000	$	337,488	107%

(1) Prior to the Merger, with the exception of Mr. Wilder, whose target annual incentive levels were provided in his employment agreement, target annual incentive levels for executive officers were determined based on a thorough analysis of market practices conducted annually by an independent compensation consultant and reviewed by the Pre-Merger O&C Committee and were set near the median of the comparable market. Following the Merger, consistent with the increase in base salaries discussed above, higher target annual incentive levels were offered to certain of our executive officers that have agreed to remain with us as a privately-held company.

(2) As a result of the Merger and our common stock no longer being publicly traded, the Earnings per Share and Operating Cash Flow targets that were originally established by the Pre-Merger O&C Committee for purposes of the 2007 annual performance bonus were not measurable. A number of Merger-related items (including the 15% price reduction provided to certain customers of TXU Energy as well as additional interest expense) were unplanned and essentially beyond our executive officers’ control. As a result, in February of 2008, the O&C Committee decided to evaluate our 2007 corporate financial performance based on an annual EFH Corp. operational EBITDA target, which is a non-GAAP financial measure. EBITDA is defined as earnings before interest, taxes, depreciation and amortization. Operational EBITDA is defined as EBITDA as adjusted by our O&C Committee as it deems appropriate in connection with its evaluation and compensation of our executive officers. For example, our O&C Committee adjusted our EBITDA to take into account the effects of unrealized mark-to-market gains and losses on positions in the long-term hedging program and certain other special or nonrecurring items including certain of the unplanned Merger-related items. Operational EBITDA is an internal measure used only for performance management purposes and management 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 targeted EFH Corp. operational EBITDA for the fiscal year ended December 31, 2007 was $4,713 million. The estimate, as of January 25, 2008, for the EFH Corp. operational EBITDA for the fiscal year ended December 31, 2007 was $4,572 million, which was slightly below target, resulting in a payout of 75% of target for this component of the overall award. Without any adjustments, our actual financial results relative to the original targets established by the Pre-Merger O&C Committee in early 2007 would have yielded a 0% payout for the corporate financial performance component of the overall award.

For Messrs. Campbell and Poole, our corporate financial performance target (i.e. operational EBITDA) accounted for 50% of the award with the remaining 50% based on specific corporate operational metrics. For Messrs. Greene, McCall and Burke, our corporate financial performance target accounted for 25% of the award, with 25% based on business unit financial performance and the remaining 50% based on business unit operational metrics.

(3) In addition to the EFH Corp. operational EBITDA performance, Mr. Greene’s award largely reflects the performance of Luminant Power, which was the business unit he led prior to his promotion to CEO of Luminant in October 2007. The targeted Luminant Power financial performance goals for the fiscal year ended December 31, 2007,

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if attained, would have resulted in a payout of 120% of target for this component of the overall award. In this regard, Luminant Power performed slightly below target resulting in a payout of 108% of target for this component of the overall award. In addition, Mr. Greene’s percentage of target payout was increased as a result of overall strong operational performance across Luminant Power in 2007, including superior fleet safety and industry leading capacity factors. Mr. Greene’s individual performance modifier increased his reward reflecting Luminant Power’s solid financial and operational performance during 2007 and his performance as a key leader of the company during an especially challenging year.

(4) In addition to the EFH Corp. operational EBITDA performance, Mr. Campbell’s award largely reflects the performance of EFH corporate services (the corporate unit that supports the overall corporation). Mr. Campbell’s payout as a percent of target was increased based on his individual performance modifier, reflecting his key role in the efficient and timely closing of the Merger, the implementation of certain other corporate initiatives, his overall leadership within the company during a challenging year and his continued, highly-effective leadership during the transition period after the close of the Merger.

(5) In addition to the EFH Corp. operational EBITDA performance, Mr. Poole’s award largely reflects the performance of EFH corporate services. Mr. Poole’s actual payout as a percentage of target was increased based on his individual performance modifier, reflecting his key role in the efficient and timely closing of the Merger, the implementation of certain other corporate initiatives, his overall leadership with the company during a challenging year and his continued, highly-effective leadership during the transition period after the close of the Merger.

(6) In addition to the EFH Corp. operational EBITDA performance, Mr. McCall’s award largely reflects the performance of Luminant Energy, which was the business unit he led prior to his promotion to Chief Operating Officer (“COO”) of Luminant in October 2007. The targeted Luminant Energy financial performance goals for the fiscal year ended December 31, 2007, if attained, would have resulted in a payout of 100% of target for this component of the overall award. In this regard, Luminant Energy performed significantly below target. While this performance would have resulted in a payout of 0% of target for this component of the overall award, the O&C Committee awarded Mr. McCall a bonus of 61% of his target incentive award, reflecting the business unit performance of Luminant Energy and Luminant and his individual performance.

(7) In addition to the EFH Corp. operational EBITDA performance, Mr. Burke’s award largely reflects the performance of TXU Energy. The targeted TXU Energy financial performance goals for the fiscal year ended December 31, 2007, if attained, would have resulted in a payout of 100% of target for this component of the overall award. In this regard, TXU Energy performed slightly below target resulting in a payout of 85% of target for this component of the overall award. However, Mr. Burke’s percentage of target payout was significantly increased as a result of strong operational performance across TXU Energy, including superior performance in customer churn, customer satisfaction and small business account origination. Mr. Burke’s individual modifier did not increase or decrease his award.

(8) In accordance with the terms of his employment agreement, and as determined by the Pre-merger O&C Committee, Mr. Wilder received a prorated award following his departure from the company on October 11, 2007 as part of his severance package. The award was paid on a target level performance.

(9) Mr. Baker retired in November 2007. During 2007, he served as CEO of Oncor Electric Delivery for four months and Vice Chairman of EFH Corp. for six months. As a result, his award reflects a blend of the performance of those businesses, as well as his own strong contributions both before and in the month after the Merger.

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Long-Term Equity Incentives

Equity Awards Prior to the Merger

Prior to the Merger, the principal long-term component of our executive compensation package consisted of performance unit awards under the 2005 Omnibus Incentive Plan. The ultimate value, if any, of awards granted under the 2005 Omnibus Incentive Plan, was directly related to performance with respect to absolute and relative total shareholder returns. In 2005, our Board selected total shareholder returns as the performance measure for the 2005 Omnibus Incentive Plan because it aligned the executive officers’ interests with the economic interests of our shareholders.

Awards under the 2005 Omnibus Incentive Plan were almost exclusively in the form of performance-based restricted stock or performance units settled in shares of our then publicly-traded common stock. All executive officers participated in the 2005 Omnibus Incentive Plan and the number of units granted varied based on the value of alternative forms of compensation available to the executive and, if applicable, the terms of individual employment agreements. The target amount of the long-term incentive compensation award was generally set at the market median of a group of peer companies. All awards under the 2005 Omnibus Incentive Plan and the Long Term Incentive Compensation Plan issued during a given year had a performance period that began on April 1 of that year and ended on March 31 three years later.

Except in the case of Messrs. Wilder, Campbell and Poole as described in the next paragraph, the ultimate payout of long-term incentive compensation awards was determined by our total shareholder returns on both an absolute and relative basis. Fifty percent of each award was based on absolute total shareholder returns over the prior three-year period. Depending upon our absolute total return for such period, the participants could earn from 0% to 150% of this portion of the original award. The remaining fifty percent of each award was based on relative total shareholder returns determined by comparing our total returns for the performance period against a peer group of companies comprised of the combined Standard & Poor's (S&P) 500 Electric Utilities and the S&P 500 Multi-Utilities Indices. Depending upon our relative total return for such periods, the participants could earn from 0% to 200% of this portion of the original award. The combination of absolute and relative components for each award meant that each incentive compensation award under the 2005 Omnibus Incentive Plan could pay out, in the aggregate, from 0% to 175% of the original amount.

The employment agreements for Messrs. Wilder, Campbell and Poole required that their long term incentive awards be measured solely on our total shareholder return performance relative to companies comprising the S&P 500 Electric Utilities Index. For these executive officers, the ultimate value of their awards, if any, was determined by our total shareholder return over future performance periods, on a relative basis, and did not contain a measure based on absolute shareholder return. Depending upon our relative total return for such periods, these executive officers could earn from 0% to 200% of the original award.

As a result of the Merger, all unvested equity awards under the 2005 Omnibus Incentive Plan vested on October 10, 2007. Except to the extent any payment for stock awarded under the 2005 Omnibus Incentive Plan was exchanged for our post-Merger equity pursuant to the Deferred Share Agreements discussed below, participants became entitled to receive consideration in the Merger for their awards. Because the Merger caused our common stock to cease to be publicly-traded, the Pre-Merger O&C Committee decided to end the performance periods for all outstanding equity awards as of the completion of the Merger and determined performance calculations based on total shareholder return performance through October 10, 2007 (the effective date of the Merger) and utilizing the $69.25 per share Merger Consideration. The cash amounts payable, which are included in the Options Exercised and Stock Vested table on page 220, were deposited into a rabbi trust on October 10, 2007, and our Named Executive Officers actually received their payouts (together with accrued interest) on January 2, 2008.

Following the Merger, no further awards will be made under the 2005 Omnibus Incentive Plan. As discussed below under the heading “Equity Awards after the Merger”, following the Merger, we adopted a new equity plan, which is designed to incent our executive officers to maximize company-wide financial and operational results.

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Equity Awards after the Merger

On December 20, 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; to motivate management and other personnel by means of growth-related incentives to achieve long range goals; and to further align the interests of management with those of our stockholders through opportunities for increased stock, or stock-based ownership in the company. It is currently expected that in April 2008, Messrs. Greene, McCall and Burke will be granted 2,000,000, 2,500,000 and 2,450,000 Stock Option Awards, respectively with the terms described below. In the future, we may also make discretionary grants of non-investment options to reward high potential and high performing individuals.

In connection with the Management Investment Opportunity, in October 2007, Messrs. Greene, McCall and Burke entered into Deferred Share Agreements with the company pursuant to which the executive officers agreed to forego certain payments they were entitled to receive in respect of equity awards that vested in connection with the Merger in return for a certain number of deferred shares of our common stock. Pursuant to the terms of their respective Deferred Share Agreements, Messrs. Greene, McCall and Burke agreed to reinvest a substantial portion of the Merger Consideration that they were entitled to receive as a result of the Merger, and became entitled to receive 600,000, 600,000 and 450,000 deferred shares, respectively, of our common stock, with each share being valued at $5.00 based upon the fully diluted equity of the company. The shares will be distributed to each of the executive officers on the earlier of the termination of such executive officer’s employment by the company or a change in the effective control of the company.

Following the Merger, our equity compensation philosophy is substantially similar to that which existed prior to the Merger, with the notable exception being that many of our executive officers now have direct, illiquid, equity investments in a privately-held company – as a result of the significant investments made by such executive officers in connection with the Management Investment Opportunity. We believe that the Management Investment Opportunity, 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, we could compel him or her to sell that stock back to us for a price equal to the fair market value at the time of that sale.

• Half of all of the Stock Option Awards to be granted will be time-based and will vest over a five year period (the “Time-Vesting Options”), except with regard to Mr. Greene whose Time Vesting Options will vest over the next two years, and for the other half of the Stock Option Awards vesting is dependent upon the company achieving certain performance-based targets over the next five fiscal years (the “Performance-Vesting Options”).

In addition, because fifty percent of the Stock Option Awards to be 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 many stakeholders. In order for the Performance-Vesting Options to vest, we will need to achieve certain EBITDA targets. EBITDA is the primary measure of operating performance in our businesses. Therefore, if an executive helps to drive sustained operating performance (which in turn drive corporate EBITDA growth), he or she can have a direct impact on the vesting of a portion of his or her equity awards. Additionally, while the number of options earned is driven by EBITDA, the ultimate value of the common stock underlying the options is determined by the overall value of the business, which reinforces the need for efficient operational performance and effective capital investment. A multi-year EBITDA target also reflects how well we are serving our constituents. For example, in the TCEH segment (which accounts for the significant majority of our EBITDA) we are ultimately a customer business, and customers have the ability to switch to competitors. We will maintain strong multi-year EBITDA performance if we do a good job serving all of our stakeholders while effectively managing our businesses.

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The material terms of our Stock Option Awards will be as follows:

• The exercise price will be an amount equal to the fair market value of a share of our common stock on the date an option is granted, which is expected to be $5.00 for the options that will be granted to Messrs. Greene, McCall and Burke in April 2008;

• The options will have a ten year term;

• Fifty percent of the Stock Option Awards will be Time-Vesting Options and will vest in 20% increments on each of the first five anniversaries (except with regard to Mr. Greene, whose options will vest in 50% increments on each of the first two anniversaries) of October 10, 2007, the date that the Merger was completed, subject to the grantee’s continued employment with the company; and

• Fifty percent of the Stock Option Awards will be Performance-Vesting Options and will 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-Vesting Options will be eligible to vest and become exercisable in equal increments of 20% at the end of fiscal years 2008, 2009, 2010, 2011 and 2012 upon our attainment of annual EBITDA performance targets. If we do not achieve the performance target for any particular fiscal year, but we do achieve a two- or three-year cumulative EBITDA performance target at the end of either of the two immediately subsequent fiscal years, then all installments of Performance-Vesting Options that did not become vested because of a missed performance target or targets in the one or two prior years, as applicable, will vest; provided that if we fail to achieve the annual performance target in either of fiscal years 2011 or 2012, then that portion of the Performance-Vesting Options that failed to vest due to our failure to achieve the annual or applicable cumulative performance targets shall nevertheless vest at the end of either of the two immediately subsequent fiscal years if the budgeted annual EBITDA target set by our Board of Directors for that fiscal year is achieved and the excess over such budgeted amount is sufficient to satisfy the shortfall from the 2011 or 2012 fiscal years, as applicable.

When the O&C Committee calculates EBITDA for purposes of determining whether we have achieved the annual EBITDA target, it plans to take our earnings before interest, taxes, depreciation and amortization plus transaction, management and/or similar fees paid to the Sponsor Group, together with such adjustments as the O&C Committee shall determine appropriate in its discretion after good faith consultation with our CEO and the Chief Financial Officer, including adjustments consistent with those included in the comparable definitions in TCEH’s senior secured credit facility 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 plan that was presented by our executive officers to the Sponsor Group in connection with the Merger.

The terms of the performance targets, including the adjustments, were negotiated with the Sponsor Group in connection with the Merger and were approved by our Board in December 2007. The EBITDA targets are intended to measure achievement of the plan presented by our executive officers to the Sponsor Group in connection with the Merger 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 plan was submitted.

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Some or all of the Performance-Vesting Options that will be granted to our executive officers could also vest when certain other events occur, including the achievement of a return or internal rate of return by our Sponsor Group. For example, if our Sponsor Group were to sell a portion of their investment in our company and, in connection with that sale, achieve a certain internal rate of return on their investment, the sale would be a qualified partial liquidity event and a percentage of the unvested Performance-Vesting Options will vest. The percentage will be based upon the percentage of our Sponsor Group’s interest that was sold in the qualified partial liquidity event. In addition, if we experience a change of control in which our Sponsor Group do not achieve the return or internal rate of return described above, a portion of the unvested Performance-Vesting Options will vest, with the percentage vesting based upon the percentage of eligible Performance-Vesting Options that had previously vested. Finally, upon the death, disability or retirement of an executive, his or her unvested Performance-Vesting Options that would have vested during the twelve month period immediately following his or her termination had the termination not occurred during that period will vest. In addition, an executive whose employment terminates due to disability or retirement, or in the case of death, his or her estate, will have one year to exercise vested options, rather than the 90-day period that is otherwise available for terminations other than for cause.

Mr. Baker retired in November 2007. He has since agreed to serve as Chairman Emeritus of EFH Corp. In that capacity, pursuant to the terms of his consulting agreement, he will be awarded 60,000 shares of restricted stock that vest in December of 2009. All of these equity awards will be granted in accordance with the terms of the 2007 Stock Incentive Plan.

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 annual incentive 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 annual incentive awards. 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 on pages 223 and 224 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 Internal Revenue Code and is a benefit for certain employees that were employed by us prior to the Merger. Our Retirement Plan contains both a traditional defined benefit 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 the retirement program with competitive practices. All participants were extended an opportunity to remain in the traditional program or transition to the cash balance component. Messrs. Greene, McCall, and Baker elected to remain in the traditional final average pay design.

Eligible employees employed after January 1, 2001 may only participate in the cash balance program. As a result, Messrs. Campbell, Poole and Burke are covered under the cash balance component. While employed by the company, Mr. Wilder was also covered under the cash balance component. Participation in our Retirement Plan has been limited for employees of all of our businesses other than Oncor, to persons employed by us at the time of the Merger. For a more detailed description of the Retirement Plan, please refer to the narrative that follows the Pension Benefits table on page 221.

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Supplemental Retirement Plan: Our Supplemental Retirement Plan provides for the payment of retirement benefits that:

• would otherwise be capped by the Internal Revenue 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 defined benefit component of the Retirement Plan only); and/or

• we or our participating subsidiaries are obligated to pay under contractual arrangements.

Messrs. Greene, McCall and Baker, the executive officers who elected to remain in the traditional defined benefit retirement plan, are 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 the executive officers hired prior to January 1, 2002. As such, it is not available to Messrs. Campbell, Poole and Burke who participate in the “make whole” portion of the Supplemental Retirement Plan (but only as it relates to the cash balance component), which only provides for the payment of retirement benefits that would otherwise be capped by the Internal Revenue Code or for the inclusion of additional accredited service under contractual arrangements. Participation in our Supplemental Retirement Plan has been limited for employees of all of our businesses other than Oncor, to persons employed by us at the time of the Merger.

For a more detailed description of the Supplemental Retirement Plan, please refer to the narrative that follows the Pension Benefits table on page 221.

Retiree Health Care:

Employees hired prior to January 1, 2002 are generally entitled to receive an employer subsidy for retiree health care coverage upon their retirement from the company. As such, Messers. Greene and McCall will be entitled to receive a subsidy from the company for retiree health care coverage upon their retirement from the company. Following his retirement, Mr. Baker began to receive this subsidy from the company. Because Messrs. Campbell, Poole and Burke were hired after January 1, 2002, they are not eligible for the employer subsidy.

Perquisites

We do not believe that a significant amount of perquisites fit within our compensation philosophy. As a result, over the years we have phased-out or altogether eliminated a number of perquisites that no longer fit our corporate culture. For a more detailed description of eliminated programs, please refer to the narrative that follows the Summary Compensation Table on page 218.

Those perquisites that have been retained 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. Wilder, who is no longer employed by us) 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, such service helps ensure greater accuracy and compliance with individual tax regulations.

Annual Executive Physical Health Exam:We pay for certain executive officers to receive annual physical health exams. The health of these executive officers is important given the vital leadership role they play in directing and operating the company. The executive officers are important assets of the company and this benefit is designed to help ensure their health and long-term ability to serve our shareholders.

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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, which begin on page 215.

Individual Compensation

Compensation of New CEO

John F. Young

Effective January 29, 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 an employment agreement with Mr. Young. The employment agreement became effective on January 29, 2008 and lasts for a period of five years. After the initial five-year term, the employment agreement provides for automatic one year renewal periods until the company or Mr. Young provides the other party with the appropriate notice to terminate the employment agreement. As compensation for his services as CEO and President, Mr. Young will be paid an annual base salary equal to $1 million with the ability to earn an annual cash bonus equal to 100% of his base salary if he achieves certain annual performance targets. 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. As part of his employment arrangement, Mr. Young made an investment in the company by purchasing $3 million in shares of our common stock under the Management Investment Opportunity. Mr. Young also received 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 the company. 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, but he will not receive the shares until the second anniversary of the grant date. 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 will not receive any additional compensation for being a member of the Board.

Mr. Young’s employment agreement includes a change in control provision. In the event that Mr. Young’s employment is terminated without cause or if he resigns for good reason within 24 months after a change in control, Mr. Young would be entitled to receive, among other things, a lump sum payment equal to two and one half times his base salary and his annual bonus target as well as a pro rata portion of his annual bonus that he would have received for the fiscal year that his employment was terminated or he resigned for good reason. 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 the our common stock and the Sponsor Group not being able to appoint a majority of the directors to our Board.

In addition to the employment agreement described above, Mr. Young has entered into other agreements that govern his equity awards. For a more complete description of the agreements applicable to Mr. Young’s investment in our common stock, please refer to the section entitled “Related Person Transactions” on page 241.

Compensation of Former CEO

C. John Wilder

The following is a summary of Mr. Wilder’s individual compensation for 2007.

Base Salary: In 2007, Mr. Wilder’s base salary was $1,250,000; this amount had not changed since he was hired in February 2004.

Annual Incentive: In accordance with his employment agreement, Mr. Wilder’s target annual incentive was 200% of base salary. As a result of Mr. Wilder’s resignation for good reason upon the closing of the Merger, he received a prorated target award of $2,083,333 that was included as part of his severance package upon his departure in October 2007.

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Long Term Equity Incentive: In accordance with his employment agreement, Mr. Wilder was awarded 300,000 performance units in 2007 under the 2005 Omnibus Incentive Plan, which vested at the closing of the Merger.

Prior to the Merger, we entered into a severance agreement with Mr. Wilder. Pursuant to the terms of the severance agreement, on October 11, 2007, Mr. Wilder resigned for “good reason” as defined in his employment agreement. Under the terms of the agreement, and consistent with our change-in-control policy, we provided Mr. Wilder certain severance payments and other benefits, including, among other things: (i) a one-time cash severance payment equal to two times the sum of his base salary and target bonus under the Executive Annual Incentive Plan ($7,500,000); (ii) a one-time, pro-rated bonus consistent with the Executive Annual Incentive Plan based on actual company performance for 2007 in the amount of $2,083,333 as determined by the Pre-Merger O&C Committee prior to the closing of the Merger; (iii) payment or reimbursement for office space and secretarial assistance for one year and (iv) the establishment of a secular trust to hold certain amounts relating to our potential obligation to gross-up certain payment obligations of Mr. Wilder under Section 4999 and 409A of the Internal Revenue Code. Mr. Wilder and EFH Corp. and certain of its affiliates also agreed to a mutual release and waiver relating to Mr. Wilder’s employment by EFH Corp. In addition, as previously disclosed, EFH Corp. made the following distributions in favor of Mr. Wilder in respect of his previously awarded incentive compensation: (i) a single lump sum cash payment in the amount of $95,681,275 for Mr. Wilder’s 2005, 2006 and 2007 long-term incentive compensation awards; (ii) a cash payment in the amount of $44,821,603 for Mr. Wilder’s earned and vested long-term incentive awards that were deferred in 2006 and 2007; (iii) distribution of a vested and deferred special incentive equity-based compensation award in the amount of $76,161,803; and (iv) distribution of all other vested benefits or account balances (totaling approximately $3 million) under certain other of our employee benefit plans. Payment of the equity-based awards was based on the number of shares of our common stock payable pursuant to each such award multiplied by $69.25, the price per share paid in the Merger for our common stock, and distributed to Mr. Wilder on January 2, 2008 from certain rabbi trusts that were established on October 10, 2007.

Compensation of Other Named Executive Officers

Michael S. Greene

The following is a summary of Mr. Greene’s individual compensation for 2007, during which he was employed as an at-will employee:

Base Salary: Prior to the closing of the Merger, Mr. Greene’s base salary was $507,000 which had not changed since October 2004. Following the Merger, Mr. Greene was promoted to CEO for Luminant and his salary was increased to $650,000 in recognition of his significantly greater level of responsibility.

Annual Incentive: Mr. Greene’s target annual incentive prior to the Merger was 60% of base salary; however, for the period beginning October 11, 2007 and ending December 31, 2007, Mr. Greene’s target annual incentive was increased to 75% of base salary. Mr. Greene earned a bonus for 2007 of $384,065, reflecting the performance of the company, the business units he led in 2007 (primarily Luminant Power) and his individual performance as previously discussed.

Long Term Equity Incentive: Mr. Greene was awarded 9,100 performance units in 2007 under the 2005 Omnibus Incentive Plan. This award vested at the closing of the Merger. In accordance with his Deferred Share Agreement, Mr. Greene agreed to forego the right to receive certain payments from the company 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 employment by the company or a change in the effective control of the company.

It is currently expected that in April 2008, Mr. Greene will be granted 2,000,000 Stock Option Awards as explained in the Long-Term Equity Incentives section under the heading “Equity Awards After the Merger” on page 205, Mr. Greene’s Time-Vesting Options will vest over a two year period as opposed to over a five year period, which will be the case for our other executive officers. Mr. Greene was considering retiring upon consummation of the Merger. Given his experience and vital leadership and to maintain continuity within Luminant, we thought it important to retain Mr. Greene and, thus, agreed to a two year vesting period for any Time-Vesting Options granted to him.

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We anticipate that we will enter into a new employment agreement with Mr. Greene in April 2008. The agreement will provide for Mr. Greene’s service as Chief Executive Officer of Luminant during a two-year term. The agreement will provide that, during the two year term, Mr. Greene will be entitled to the terms outlined below:

1. a minimum annual base salary of $650,000;

2. target annual bonuses under the Executive Annual Incentive Plan of 75% of his base salary and

3. stock options to purchase 2,000,000 shares of our common stock of at a price per share of $5.00.

David A. Campbell

We entered into an employment agreement with Mr. Campbell effective May 14, 2004, which was amended on September 28, 2007 and October 4, 2007. The agreement, as amended, entitled Mr. Campbell to the following individual compensation for 2007:

Base Salary:In 2007, Mr. Campbell’s base salary was $382,000; this amount has not changed since October 2004, when his salary was adjusted to its current level in recognition of increased responsibilities.

Annual Incentive: On October 10, 2007, we entered into an Additional Payment Agreement with Mr. Campbell, pursuant to which we agreed, among other things, that Mr. Campbell’s cash bonus under the Executive Annual Incentive Plan would not be less than the percentage of the target pool established under the Annual Incentive Plan used in determining the 2007 award for all other participants in the Annual Incentive Plan with a personal modifier of at least 100%. In 2007, as a result of the company’s results as previously discussed, as well as Mr. Campbell’s individual performance, he earned a bonus of $300,481.

Long Term Equity Incentive: In accordance with his employment agreement, Mr. Campbell was awarded 40,000 performance units in 2007 under the 2005 Omnibus Incentive Plan. This award vested upon the completion of the Merger.

In 2007, Mr. Campbell’s employment agreement was amended to address a number of issues associated with the Merger. Under the terms of his employment agreement, as amended, if Mr. Campbell were to (1) be terminated by the company without cause or (2) resign for good reason or (3) depart during a 30-day period commencing on April 10, 2008, he would be entitled to receive a cash payment equal to the guaranteed number of long term incentive performance units issuable for 2008 and 2009 multiplied by $69.25. Upon such a qualifying termination, Mr. Campbell would be entitled to receive a cash payment of $5,540,000, representing the amount agreed to be paid with regard to his ungranted 2008 and 2009 equity awards (based on 40,000 performance units for each of 2008 and 2009).

David P. Poole

We entered into an employment agreement with Mr. Poole effective May 1, 2004, which was amended on September 28, 2007, October 4, 2007 and January 2, 2008. The agreement, as amended, entitled Mr. Poole to the following individual compensation for 2007:

Base Salary: In 2007, Mr. Poole’s base salary was $307,000. Pursuant to the January 2, 2008 amendment to his employment agreement, Mr. Poole’s base salary was increased to the rate of $66,666 per month.

Annual Incentive: On October 10, 2007, we entered into an Additional Payment Agreement with Mr. Poole, pursuant to which the company has agreed, among other things, that Mr. Poole’s cash bonus under the Executive Annual Incentive Plan would not be less than the percentage of the target pool established under the Annual Incentive Plan used in determining the 2007 award for all other participants in the Annual Incentive Plan with a personal modifier of at least 100%. In 2007, as a result of the company’s results, as previously discussed, as well as Mr. Poole’s individual performance, he earned a bonus of $220,487.

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Long Term Equity Incentive: In accordance with his employment agreement, Mr. Poole was awarded 30,000 performance units in 2007 under the 2005 Omnibus Incentive Plan. This award vested upon the completion of the Merger.

On January 15, 2008, pursuant to an amendment to his employment agreement, 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 the company and (ii) $4,155,000, representing the amount agreed to be paid with regard to his ungranted 2008 and 2009 long term performance units (based on 30,000 performance units for each of 2008 and 2009 multiplied by $69.25). In the amendment, Mr. Poole agreed that the payment of such amounts represents full and final payment for the cash severance and ungranted equity awards provided for under his employment agreement and that he would have no further right to any payment under our bonus plans or to participate in any of our equity-based compensation programs. He also agreed to remain with us until such time as a new General Counsel was hired, to ensure an orderly transition. Mr. Poole left the company on March 31, 2008. He resigned as General Counsel on March 24, 2008 when Mr. Robert C. Walters was hired to serve as our General Counsel.

Michael T. McCall

The following is a summary of Mr. McCall’s individual compensation for 2007 during which he was employed as an at-will employee:

Base Salary: Prior to the Merger, Mr. McCall’s base salary was $325,000. Following the Merger, Mr. McCall’s salary was increased to $500,000 in recognition of the increased responsibilities of his new role as Chief Operating Officer for Luminant.

Annual Incentive: Mr. McCall’s target annual incentive prior to the Merger was 60% of base salary; however, for the period beginning October 11, 2007 and ending December 31, 2007, Mr. McCall’s target annual incentive was increased to 75% of base salary. Mr. McCall earned a bonus for 2007 of $145,800, reflecting the performance of Luminant Energy and Luminant Holdings and his individual performance.

Long Term Equity Incentive: Mr. McCall was awarded 13,600 performance units in 2007 under the 2005 Omnibus Incentive Plan. This award vested at Merger close. In accordance with his Deferred Share Agreements with the company, Mr. McCall agreed to forego the right to receive certain payments from the company 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 employment by the company or a change in the effective control of the company. It is currently expected that in April 2008, Mr. McCall will be granted 2,500,000 Stock Option Awards as explained in the Long-Term Equity Incentives section under the heading “Equity Awards After the Merger” on page 205.

We anticipate that we will enter into a new employment agreement with Mr. McCall in April 2008. The agreement will provide for Mr. McCall’s service as Chief Operating Officer of Luminant during a three-year term, which term is automatically extended for successive one-year periods unless terminated by the company or Mr. McCall. The agreement will provide that, during the three year term, Mr. McCall will be entitled to the terms outlined below:

1. a minimum annual base salary of $500,000;

2. target annual bonuses under the Executive Annual Incentive Plan of 75% of his base salary and

3. stock options to purchase 2,500,000 shares of our common stock of at a price per share of $5.00.

James A. Burke

Mr. Burke’s previous agreement with the company entitled him to the following individual compensation for 2007:

Base Salary: In 2007, Mr. Burke’s base salary was $275,000 and had not been increased since he was hired as Senior Vice President – Consumer Markets in 2004. He was promoted to CEO of TXU Energy in 2005, but his salary remained frozen at $275,000. Following the Merger close, Mr. Burke’s salary was increased to $600,000, in recognition of a more appropriate salary for his responsibilities.

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Annual Incentive: Mr. Burke’s target annual incentive prior to the Merger was 60% of base salary; however, for the period beginning October 11, 2007 and ending December 31, 2007, Mr. Burke’s target annual incentive was increased to 75% of base salary. On October 10, 2007, we entered into an Additional Payment Agreement with Mr. Burke, pursuant to which the company agreed that Mr. Burke’s cash bonus under the Executive Annual Incentive Plan would not be less than the percentage of the target pool established under the Annual Incentive Plan used in determining the 2007 award for all other participants in the Annual Incentive Plan with a personal modifier of at least 100%. In 2007, Mr. Burke earned a bonus of $274,050 reflecting the performance of the company, the business unit he led in 2007 (TXU Energy) and his individual performance.

Long Term Equity Incentive: Mr. Burke was awarded 14,500 performance units in 2007 under the 2005 Omnibus Incentive Plan. This award vested at Merger close. In accordance with his Deferred Share Agreement, Mr. Burke agreed to forego the right to receive certain payments from the company 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 employment by the company or a change in the effective control of the company. It is currently expected that in April 2008, Mr. Burke will be granted 2,450,000 Stock Option Awards as explained in the Long-Term Equity Incentives section under the heading “Equity Awards After the Merger” on page 205.

We entered into a new employment agreement with Mr. Burke effective December 31, 2007. The agreement provides for Mr. Burke’s service as Chief Executive Officer of TXU Energy during a three-year term, which term is automatically extended for successive one-year periods unless terminated by the company or Mr. Burke. The agreement provides that, during the three year term, Mr. Burke will be entitled to the terms outlined below:

1. a minimum annual base salary of $600,000;

2. target annual bonuses under the Executive Annual Incentive Plan of 75% of his base salary and

3. stock options to purchase 2,450,000 shares of our common stock of at a price per share of $5.00.

T. L. Baker

The following is a summary of Mr. Baker’s individual compensation for 2007 during which he was employed as an at-will employee until he retired in November 2007:

Base Salary: In 2007, Mr. Baker’s base salary was $632,000.

Annual Incentive:Mr. Baker retired in November 2007. During 2007, he served as CEO of Oncor for four months and Vice Chairman of EFH Corp. for six months. As a result, his pro-rated bonus for 2007 of $337,488 reflects a blend of the performance of those businesses, as well as his own strong contributions both before and in the month after the Merger.

Long Term Equity Incentive: Based on Mr. Baker’s indication that he would retire following the close of the Merger, he was not awarded any performance units in 2007 under the 2005 Omnibus Incentive Plan.

We anticipate that we will enter into a consulting agreement with Mr. Baker in April 2008. It is currently expected that the consulting agreement will have a term of up to two years and will provide for an annual consulting fee of $250,000. In addition, it is expected that Mr. Baker will receive a grant of 60,000 shares of restricted common stock under the 2007 Stock Incentive Plan. These shares will vest on the second anniversary of the consulting agreement provided that Mr. Baker continues to provide consulting services to the company during such period.

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Contingent Payments

We have entered into an employment agreement with Mr. Burke and expect to enter into employment agreements with Mr. Greene and Mr. McCall. Mr. Burke’s agreement generally provides, and Messrs. Greene and McCall’s agreements are expected to provide, 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. In addition, we maintain a change in control policy and severance plan that provide for these types of payments and benefits in the event an executive officer does not have an employment agreement with us. For a description of the applicable provisions in Mr. Burke’s employment agreement and our change in control policy and severance plan see “Potential Payments upon Termination or Change in Control” beginning on page 225.

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.

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 and performance units granted under our Long-Term Incentive Compensation Plan and 2005 Omnibus 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.

Income Tax Considerations

Section 162(m) of the Internal Revenue 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. As a result of the Merger, EFH Corp. was a privately-held company on the last day of 2007. As a result, Section 162(m) will not limit the tax deductibility of any executive compensation for 2007.

The O&C Committee administers our compensation programs with the good faith intention of complying with Section 409A of the Internal Revenue Code.

The Internal Revenue Code also limits the tax deductibility by corporations of amounts paid to certain persons that are treated as excess parachute payments under Code Section 280G. Excess parachute payments are also subject to an excise tax payable by the recipient of such payments. Excess parachute payments could arise with regard to payments made to executive officers in connection with a transaction that gives rise to a change in our ownership or effective control or in the ownership of a substantial portion of our assets. For example, the tax gross-up payments provided to our executive officers in connection with the Merger, as described in more detail in footnote 5 to the Summary Compensation Table on pages 216 and 217, were excess parachute payments and were not deductible by the company, nor were any of the underlying excess parachute payments that gave rise to the excise tax.

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

Marc S. Lipschultz

Kenneth Pontarelli

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The following table provides information for the fiscal years ended December 31, 2006 and 2007 regarding the aggregate compensation paid to the Named Executive Officers.

Summary Compensation Table

Name and Principal Position	Year	Salary ($)(1)	Stock Awards ($)(2)	Non-Equity Incentive Plan Compensation ($)(3)	Change in Pension Value and Non- qualified Deferred Compensation Earnings ($)(4)	All Other Compensation ($)(5)	Total ($)
M. S. Greene President and CEO of Luminant	2007 2006	536,792 507,000	596,284 1,145,979	384,065 220,000	189,411 1,222,893	347,747 229,765	2,054,299 3,325,637
David A. Campbell Executive Vice President and Chief Financial Officer of EFH Corp.	2007 2006	382,000 382,000	1,339,728 1,311,787	300,481 230,000	14,667 30,639	2,342,814 53,682	4,379,690 2,008,108
David P. Poole Executive Vice President and Former General Counsel of EFH Corp.	2007 2006	307,000 307,000	1,099,176 841,275	220,487 120,000	13,388 22,696	2,627,981 43,082	4,268,032 1,334,053
Michael T. McCall Chief Operating Officer of Luminant	2007 2006	345,958 232,000	521,450 541,274	145,800 140,000	77,035 153,820	116,712 93,336	1,206,955 1,160,430
James A. Burke President and CEO of TXU Energy	2007 2006	342,712 275,004	454,478 512,932	274,050 100,000	9,864 15,962	978,189 52,233	2,059,293 956,131
C. John Wilder Former CEO of EFH Corp.	2007 2006	989,583 1,250,000	9,026,216 6,390,038	0 1,625,000	103,076 185,454	27,843,146 564,056	37,962,021 10,014,548
T. L. Baker Chairman Emeritus of EFH Corp.	2007 2006	536,242 632,000	350,298 459,986	337,488 130,000	23,800 580,050	438,614 302,169	1,686,442 2,104,205

(1) As more fully discussed under the section entitled “Base Salary” beginning on page 200, effective as of October 11, 2007, EFH Corp. increased the base salaries for certain of its executive officers who agreed to remain employed by EFH Corp. or its subsidiaries following the Merger. As a result, the amounts reported as “Salary” for Messrs. Greene, McCall and Burke reflect a blend of their pre-Merger salary and their increased post-Merger salary. Further, because Mr. Wilder resigned effective with the closing of the Merger and Mr. Baker retired in November 2007, the amounts reported as “Salary” for these individuals reflect the actual salary payments made to them prior to the termination of their employment with EFH Corp.

(2) 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 performance units awarded under the Long-Term Incentive Compensation Plan and the 2005 Omnibus Incentive Plan from 2004-2007. The Long-Term Incentive Compensation Plan and 2005 Omnibus Incentive Plan are comprehensive, stock-based incentive compensation plans providing for common stock-based awards to designated employees and non-employee directors. The reported amount includes the applicable 2007 compensation cost for restricted stock or performance units awarded in 2004, 2005, 2006 and 2007. Aside from the SFAS 123R compensation cost, neither the “Stock Awards” nor the “All Other Compensation” columns include amounts attributable to equity awards that vested on or before the closing of the Merger. For more information on stock vested in connection with the closing of the Merger, please refer to the Options Exercised and Stock Vested—2007 table on page 220.

The material terms of the 2007 awards made under the 2005 Omnibus Incentive Plan are described in the narrative that follows the Grants of Plan-Based Awards table on page 219. The 2007 awards to Messrs. Wilder, Campbell and Poole reflect the terms of individual employment agreements which entitled them to receive annual awards of 300,000, 40,000 and 30,000 performance units, respectively.

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(3) Amounts reported as “Non-Equity Incentive Plan Compensation” were earned by the executive in 2007 and relate to 2007 awards pursuant to the Executive Annual Incentive Plan. With the exception of Mr. Wilder’s prorated award, those awards were paid to the executives in 2008 and are described in the section entitled “Executive Annual Incentive Plan” beginning on page 201. As part of his severance package, on October 11, 2007, Mr. Wilder received a prorated award under the Executive Annual Incentive Plan. The award, which is reported under “All Other Compensation,” was paid on a target level performance.

(4) 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 Internal Revenue Code and covered by ERISA. The Retirement Plan contains both a traditional defined benefit component and a cash balance component. Messrs. Greene, Baker and McCall are covered under the traditional defined benefit component and Messrs. Campbell, Poole and Burke are covered under the cash balance component. While employed by the company, Mr. Wilder 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 on page 221. There are no above market earnings for nonqualified deferred compensation.

(5) Amounts reported as “All Other Compensation” are attributable to the executive officer’s participation in certain plans and as otherwise described in this footnote.

Amounts reported under “All Other Compensation” include tax gross-ups paid to EFH Corp.’s executive officers in connection with the Merger for excise taxes resulting from the application of Code Section 280G as a result of certain benefits or payments they received in connection with the Merger. As required under their employment agreements, EFH Corp. agreed to reimburse Messrs. Wilder, Campbell, Burke and Poole for all excise taxes that are imposed on them, including those imposed under Code section 4999, and any income and excise taxes that are payable by the executive officer as a result of any such reimbursements. The tax gross-up amount is payable to the executive officer for any excise tax incurred regardless of whether his employment is terminated. The actual amount paid by EFH Corp., however, is based upon whether the executive officer’s employment is terminated. As a result of this tax gross-up obligation, on October 10, 2007, EFH Corp. deposited the following amounts into a rabbi trust to gross-up the effect of taxes on the payouts of outstanding equity awards under the 2005 Omnibus Inventive Plan: $14,010,408 for Mr. Wilder, $2,275,287 for Mr. Campbell, $434,549 for Mr. Burke and $2,519,629 for Mr. Poole. The amounts deposited into the rabbi trust are included in the amounts reported under “All Other Compensation” for Messrs. Wilder, Campbell, Burke and Poole. In accordance with its terms, on January 2, 2008 the rabbi trust paid to the IRS taxes owed by these executive officers as a result of the change in control. In addition, the amounts reported under “All Other Compensation” also include tax gross-ups that have been, or will be, paid to our executive officers to offset the effect of taxes on the Salary Deferral Program benefits the executive officers received as a result of the Merger in the following amounts: $64,421 for Mr. Wilder, $21,932 for Mr. Campbell, $19,894 for Mr. Burke and $26,002 for Mr. Poole. The amount reported under “All Other Compensation” for Mr. Wilder also includes tax gross-ups related to the Deferred and Incentive Compensation Plan in the amount of $180,366 and for his severance payments paid under his employment agreement in the amount of $3,428,619. Mr. Wilder’s tax gross-ups related to the Salary Deferral Program, Deferred and Incentive Compensation Plan and the severance payments paid under his employment agreement were paid to him in October 2007. Further, the amount reported under “All Other Compensation” for Mr. Burke includes a tax gross-up in the amount of $437,575 to offset the effect of taxes on a portion of his equity awards under the 2005 Omnibus Inventive Plan that were deferred pursuant to his Deferred Share Agreement. For purposes of Code Section 280G, the tax gross-up amounts were calculated using the Merger Consideration ($69.25), and, to the extent that any payout was conditioned upon or determined based on achievement of performance criteria, actual performance through the date the Merger closed was used to determine the payout level. The calculation is based upon Internal Revenue Code Section 4999, which provides for an excise tax rate of 20%, and assumes a 35% federal income tax rate, a 1.45% Medicare tax rate and a 0% state income tax rate. The executive officers reside in the state of Texas, which does not impose a state income tax.

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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. 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. Greene, $10,126; Campbell, $4,500; Poole, $13,815; McCall, $10,125; Burke, $13,499; Wilder, $13,498 and Baker, $10,902. Upon the closing of the Merger, 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 include a cash allocation of $30,100, which was paid into each executive officer’s Thrift Plan account on October 19, 2007.

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 on pages 223 and 224 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 2007 under the Salary Deferral Program, which are included under “All Other Compensation” in the Summary Compensation Table, include these amounts for Messrs. Greene, $53,679; Campbell, $0; Poole, $24,560; McCall, $27,677; Burke, $27,417; Wilder, $79,167 and Baker, $42,899. Upon the closing of the Merger, all unvested EFH Corp. matching contributions to the Salary Deferral Program became fully vested.

Under EFH Corp.’s Split-Dollar Life Insurance Program, split-dollar life insurance policies are purchased for eligible executive officers of EFH Corp. and its participating subsidiaries. The eligibility provisions of this program were modified in 2003 so that no new participants were added after December 31, 2003. Accordingly, Messrs. Campbell, Poole, Burke and Wilder were not eligible to participate in the Split-Dollar Life Insurance Program. The death benefits of participants’ insurance policies are equal to two, three or four times their annual Split-Dollar Life Insurance Program compensation, depending on their executive category. Individuals who first became eligible to participate in the Split-Dollar Life Insurance Program after October 15, 1996, vested in the insurance policies issued under the Split-Dollar Life Insurance Program over a six-year period. 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, with respect to executive officers, 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 EFH Corp.’s executive officers were made on a non-split-dollar life insurance basis during 2007, such premiums were fully taxable to the executive officers, and EFH Corp. provided tax gross-up payments to offset the effect of such taxes. Additional interest was attributed to the executive officers in 2007 relative to premium payments which had been made on their behalf prior to August 1, 2002. During 2006, the amounts reported under “All Other Compensation” in the Summary Compensation Table attributable to the aggregate amount of premiums and interest amounted to the following for Messrs. Greene, $150,490; McCall $24,037 and Baker, $204,649.The amount reported under “All Other Compensation” also includes tax gross-ups provided to offset the effect of income taxes on premium payments made on a non-split dollar life insurance basis during 2007 as follows for Messrs. Greene, $91,571; McCall, $13,787 and Baker, $121,633. At the Merger, 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.

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Amounts reported under “All Other Compensation” for Mr. Wilder also include a severance payment of $9,744,407, which consists of (i) a one-time cash severance payment equal to two times the sum of his base salary and target bonus under the Executive Annual Incentive Plan ($7,500,000), (ii) a one-time, pro-rated bonus consistent with the Executive Annual Incentive Plan based on actual company performance for 2007 in the amount of $2,083,333 as determined by the Pre-Merger O&C Committee prior to the closing of the Merger and (iii) payment or reimbursement for office space and secretarial assistance for one year. Please refer to the section entitled “Compensation of Former CEO” on page 209 for a more complete description of Mr. Wilder’s severance arrangement.

Amounts reported under “All Other Compensation” also include the perquisites summarized in the following table for our Named Executive Officers.

2007 Perquisites for Named Executive Officers

Name	Aircraft Usage(1)		Financial Planning		Executive Physical		Home Security Expense		Country Club(2)		Other(3)		Total
M. S. Greene		0	$	9,430	$	2,350		0		0		0	$	11,780
David A. Campbell		0	$	9,430	$	1,565		0		0		0	$	10,995
David P. Poole		0	$	5,695	$	2,350		0	$	2,030	$	3,800	$	13,875
Michael T. McCall		0	$	9,430		0		0	$	1,314		0	$	10,744
James A. Burke		0	$	8,270		0		0	$	6,885		0	$	15,155
C. John Wilder	$	40,188	$	9,430	$	2,350	$	23,089	$	186,028	$	2,000	$	263,085
T. L. Baker		0	$	9,430		0		0		0	$	19,000	$	28,430

(1) As recommended by our independent security advisor and as provided in his employment agreement, Mr. Wilder was provided use of company aircraft for personal use while he was employed by EFH Corp. Subsequent to the Merger, EFH Corp. has made arrangements to sell its aircraft as it no longer plans to own or operate aircraft.

With respect to personal aircraft usage, based upon the review and findings of an independent, third-party consultant, aggregate incremental costs to EFH Corp. include variable costs (including fuel and maintenance costs, among other items), but exclude non-variable or fixed costs (such as pilot salaries and hanger rent, among other items), that would have been incurred regardless of whether there was any personal use.

In addition to Mr. Wilder’s usage, certain other executive officers’ family members and/or guests accompanied the executive officers on the corporate aircraft to attend business functions. Because the aircraft was already being used for business purposes, there was no incremental cost to EFH Corp. for these persons’ travel.

The values reported for perquisites other than aircraft usage are actual amounts spent by EFH Corp.

(2) In accordance with the terms of his employment agreement, in August 2007, EFH Corp. purchased a country club membership for Mr. Wilder. The amount above reflects a membership initiation fee in the amount of $185,000 and one month’s dues.

(3) Amounts in the “Other” column include Mr. Poole’s spouse’s expense while accompanying him on business travel, event tickets for Mr. Wilder and retirement planning for Mr. Baker.

For a discussion of the terms of the employment agreements with the Named Executive Officers, please see the “Individual Compensation” section beginning on page 209.

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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, 2007.

Grants of Plan-Based Awards – 2007

Name	Grant Date	Estimated Possible Payouts Under Non- Equity Incentive Plan Awards(1)			Estimated Future Payouts Under Equity Incentive Plan Awards(2)			Grant Date Fair Value of Stock Award ($)(3)
		Threshold ($)	Target ($)	Max. ($)	Threshold (#)	Target (#)	(Max) (#)
M. S. Greene	01/01/07	175,125	350,025	1,400,100
	04/01/07				9,100	9,216	9,216	521,430
David A. Campbell	01/01/07	114,600	229,200	916,800
	04/01/07				40,000	40,510	40,510	2,292,000
David P. Poole	01/01/07	92,100	184,200	736,800
	04/01/07				30,000	30,382	60,764	2,435,700
Michael T. McCall	01/01/07	120,000	240,000	960,000
	04/01/07				13,600	13,773	13,773	779,280
James A. Burke	01/01/07	118,125	236,250	945,000
	04/01/07				14,500	14,685	14,685	830,850
C. John Wilder	01/01/07	1,250,000	2,500,000	10,000,000
	04/01/07				300,000	303,822	303,822	17,190,000
T. L. Baker	01/01/07	189,600	379,200	1,516,800

(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. The actual awards for the 2007 plan year were paid in March 2008 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” beginning on page 201.

(2) The amounts reported as “Threshold” under the heading “Estimated Future Payouts Under Equity Incentive Plan Awards” represent the number of performance units granted to the executive officer in 2007 under the 2005 Omnibus Incentive Plan (the “2007 Awards”). “Target” represents awards plus invested dividends through October 9, 2007. “Max” represents the number of shares that were paid out upon the change in control that occurred in connection with the Merger. All 2007 Awards provided for the issuance of performance units, each having a value equal to one share of our common stock. The 2007 Awards had an effective date of April 1, 2007. By action of the Pre-Merger O&C Committee, all 2007 Awards vested upon completion of the Merger.

The number of performance units awarded to Mr. Poole pursuant to his 2007 Award depended on a formula comparing our total shareholder return over the applicable performance period to the total shareholder return of the companies comprising the S&P 500 Electric Utilities Index. Based on the total shareholder return through the date of the Merger, the number of performance units actually awarded to Mr. Poole was adjusted to become 200% of the original granted amount, plus dividends earned on the shares of common stock underlying such units.

The number of performance units awarded to Messrs. Greene, Campbell, McCall, Burke, Wilder and Baker pursuant to their 2007 Awards were determined using a formula based on our absolute and relative total shareholder returns over the applicable performance period. However, the number of performance units awarded pursuant to these 2007 Awards was capped so that the actual payout was 100% of the target, plus dividends earned on the shares of common stock underlying such units.

(3) The amounts reported under “Grant Date Fair Value of Stock Award” represent the compensation expense under SFAS 123R for the entire performance period related to the 2007 Awards.

Outstanding Equity Awards at Fiscal Year-End– 2007

As a result of the Merger, there were no unvested stock awards held by the Named Executive Officers as of December 31, 2007.

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The following table sets forth information regarding the vesting of equity awards held by the Named Executive Officers during 2007:

Options Exercised and Stock Vested – 2007

	Stock Awards
Name	Year of Grant	Number of Shares Acquired on Vesting (#)		Value Realized on Vesting ($)
M. S. Greene	2004		234,589	$	15,084,090.34
	2005		52,508	$	3,636,174.47
	2006		23,875	$	1,653,336.02
	2007		9,216	$	638,202.82
		Total:	320,188	$	21,011,803.65
David A. Campbell	2004		172,969	$	11,121,909.86
	2005		85,727	$	5,936,610.90
	2006		57,987	$	4,015,605.22
	2007		40,510	$	2,805,287.11
		Total:	357,193	$	23,879,413.09
David P. Poole	2004		86,485	$	5,560,954.73
	2005		64,295	$	4,452,458.36
	2006		43,490	$	3,011,703.92
	2007		60,764	$	4,207,930.67
		Total:	255,034	$	17,233,047.68
Michael T. McCall	2004		60,539	$	3,892,668.10
	2005		15,002	$	1,038,906.76
	2006		47,750	$	3,306,672.05
	2007		13,773	$	953,797.62
		Total:	137,064	$	9,192,044.53
James A. Burke	2004		78,917	$	5,074,371.48
	2005		26,198	$	1,814,191.23
	2006		23,875	$	1,653,336.02
	2007		14,685	$	1,016,916.58
		Total:	143,675	$	9,558,815.31
C. John Wilder	2004		648,634	$	41,707,160.74
	2005		642,954	$	44,524,582.72
	2006		434,903	$	30,117,039.18
	2007		303,822	$	21,039,653.33
		Total:	2,030,313	$	137,388,435.97
T. L. Baker	2004		324,317	$	20,853,580.50
	2005		52,508	$	3,636,174.47
	2006		19,136	$	1,325,193.00
		Total:	395,961	$	25,814,947.97

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As a result of the Merger, all unvested equity awards under the 2005 Omnibus Incentive Plan vested on October 10, 2007. Except to the extent they agreed to forego a portion of the payment that they were entitled to receive in exchange for deferred shares of the post-Merger equity of EFH Corp., participants became entitled to receive consideration in the Merger for their outstanding equity awards. Because the Merger caused our common stock to cease to be publicly-traded, the Pre-Merger O&C Committee decided to end the performance periods under outstanding equity awards as of the completion of the Merger and determined performance calculations based on relative total shareholder return performance and/or absolute total shareholder return performance through the effective date of the Merger utilizing the $69.25 per share Merger Consideration. The cash amounts payable were determined by taking the number of shares of common stock issuable based upon the performance calculations, multiplied by $69.25. The equity awards that vested on October 10, 2007 as a result of the Merger were paid on January 2, 2008. Because these deferred payments meet the definition of “nonqualified deferred compensation” under the federal tax laws, these amounts are also reported in the “Registrant Contribution” column in the Nonqualified Deferred Compensation – 2007 table. Also, the amount reported as “Value Realized on Vesting” for Messrs. Greene, McCall and Burke include payments of $3,000,000, $3,000,000, and $2,250,000, respectively, that they were entitled to receive in respect of outstanding equity awards, but which the executives 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. As a result of the Merger, no further awards will be made under the 2005 Omnibus Incentive Plan. As discussed above under the heading “Equity Awards after the Merger,” EFH Corp. adopted a new equity plan, which is designed to incent our executive officers to maximize company-wide financial results and operational performance.

Under the terms of the Long-Term Incentive Compensation Plan, the maximum amount of any award that may be paid in any one year to any of the executive officers is the fair market value of 200,000 shares of EFH Corp.’s common stock, determined as of the first day of such calendar year. The portion of any award that cannot be fully paid in any year as a result of this maximum amount limitation is automatically deferred until a subsequent year when it can be paid in accordance with applicable legal requirements without exceeding the maximum amount. As a result of this limitation, amounts reported as “Value Realized on Vesting” include the following amounts of shares and/or performance units for the performance period ending March 31, 2007 (plus any dividends), which were deferred in May 2007 and subsequently paid in connection with the Merger: 323,686 shares valued at $22,415,251 for Mr. Wilder; 161,843 shares valued at $11,207,626 for Mr. Baker; 12,584 shares valued at $871,416 for Mr. Campbell and 74,084 shares valued at $5,130,317 for Mr. Greene. Except with regard to the amounts payable to Mr. Wilder, who received payment for his deferred shares and performance units in January 2008, these amounts are not included in the Nonqualified Deferred Compensation Table on page 223 because they were paid in October 2007 as a result of the Merger.

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, 2007:

Pension Benefits – 2007

Name	Plan Name	Number of Years Credited Service (#)	PV of Accumulated Benefit ($)	Payments During Last Fiscal Year ($)
M. S. Greene	Retirement Plan Supplemental Retirement Plan	37.1667 37.1667	1,317,259 3,831,600	0 0
David A. Campbell (1)	Retirement Plan Supplemental Retirement Plan	2.5833 5.1667	20,204 32,905	0 0
David P. Poole (2)	Retirement Plan Supplemental Retirement Plan	2.6667 5.3334	20,833 22,886	0 0
Michael T. McCall	Retirement Plan Supplemental Retirement Plan	25.3333 25.3333	425,554 415,434	0 0
James A. Burke	Retirement Plan Supplemental Retirement Plan	2.1667 2.1667	15,036 12,825	0 0
C. John Wilder	Retirement Plan Supplemental Retirement Plan	2.6667 2.6667	26,518 401,531	0 0
T. L. Baker	Retirement Plan Supplemental Retirement Plan	37.1667 37.1667	1,272,175 4,997,432	8,467 33,261

(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.

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(2) Mr. Poole’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.

EFH Corp. and its participating subsidiaries maintain the Retirement Plan, which is intended to be qualified under applicable provisions of the Internal Revenue 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 are 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 effective in 2002. Participation in EFH Corp.’s Retirement Plan has been limited for employees of all of its businesses other than Oncor, to persons employed by EFH Corp. (or its participating subsidiaries) at or before the time of the Merger.

Annual retirement benefits under the traditional defined benefit component, which applied during 2007 to Messrs. Greene, McCall and Baker, are 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 2007 to Messrs. Campbell, Poole, Burke and Wilder (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 defined benefit component of the Retirement Plan are not subject to any reduction for Social Security payments but are limited by provisions of the Internal Revenue Code.

The Supplemental Retirement Plan provides for the payment of retirement benefits, which would otherwise be limited by the Internal Revenue 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 defined benefit 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 for employees of all of its businesses other than Oncor, to persons employed by EFH Corp. (or its participating subsidiaries) at or before the time of the Merger.

The table set forth above illustrates present value on December 31, 2007 of each executive’s Retirement Plan benefit and benefits payable under the Supplemental Retirement Plan, based on their years of service and remuneration through December 31, 2007. Benefits accrued under the Supplemental Retirement Plan after December 31, 2004, are subject to Section 409A of the Internal Revenue 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 defined benefit 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 6.55% 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, 2007 at 6.55%. 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, 2007:

Nonqualified Deferred Compensation – 2007

Name	Executive Contributions in Last FY ($)	Registrant Contributions in Last FY ($) (2)	Aggregate Earnings in Last FY ($)	Aggregate Withdrawals/ Distributions($)	Aggregate Balance at Last FYE ($)
M. S. Greene	53,679	5,981,392	688,648	340,425	9,217,470
David A. Campbell	0	15,032,790	157,336	0	15,407,469
David P. Poole	60,700	14,216,282	158,922	0	14,903,071
Michael T. McCall	27,677	5,327,053	321,098	205,269	6,667,362
James A. Burke	27,417	5,383,985	42,173	0	5,561,521
C. John Wilder(1)	79,167	139,793,418	27,053,127	3,101,052	245,492,957
T. L. Baker	42,899	5,004,266	3,735,586	11,021,022	10,287,320

(1) The amount under “Aggregate Balance at Last FYE” for Mr. Wilder includes the value of the trust shares awarded to Mr. Wilder to compensate him for a portion of his forgone compensation upon leaving his previous employer to join EFH Corp. Mr. Wilder had to forfeit certain benefits from his prior employer, including unvested stock options, unvested long term incentive, deferred cash awards, restricted cash payments and supplemental executive retirement. To partially compensate Mr. Wilder for a portion of his forgone compensation and to conserve cash payments at a time during which EFH Corp. was cash constrained, we established a rabbi trust, which held 1,000,000 shares of EFH Corp.’s common stock purchased for the benefit of Mr. Wilder by EFH Corp. These shares were acquired in connection with the Merger, and the value of these shares was paid in cash to Mr. Wilder on January 2, 2008. The value of these shares at the time of distribution on January 2, 2008 was $76,161,803. EFH Corp.’s purchase of these shares and the establishment of the trust were previously reported in EFH Corp.’s 2005 proxy statement.

(2) Amounts reported under “Registrant Contributions in last FY” include the following amounts for performance units that vested upon consummation of the Merger, but were deferred and paid in January 2008: Mr. Greene, $2,927,713; Mr. Campbell, $12,757,503; Mr. Poole, $11,672,093; Mr. McCall, $2,299,376; Mr. Burke, $2,234,444 and Mr. Baker, $4,961,367. These amounts are disclosed under this table because they meet the definition of “nonqualified deferred compensation” under federal tax laws. These amounts, however, are also disclosed above in the table entitled “Options Exercised and Stock Vested – 2007”. In addition, the amount reported under “Registrant Contributions in last FY” for Mr. Wilder includes $125,403,884 related to vested and deferred performance units, which was paid to him in 2008 as a result of the Merger. Amounts reported under “Registrant Contributions in last FY” also include the following tax gross-ups that were funded into a rabbi trust in favor of certain of EFH Corp.’s executive officers for excise taxes resulting from the application of Code Section 280G to the Merger Consideration that they became entitled to receive as a result of the vesting of their performance units in connection with the Merger: $14,010,408 for Mr. Wilder, $2,275,287 for Mr. Campbell, $434,549 for Mr. Burke, and $2,519,629 for Mr. Poole. In accordance with its terms, on January 2, 2008 the rabbi trust paid to the IRS the taxes owed by these executive officers as a result of the Merger. Also, the amount reported in “Registrant Contributions in Last FY” for Messrs. Greene, McCall and Burke include payments of $3,000,000, $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.Further, the amount reported under “Registrant Contributions in last FY” for Mr. Burke includes a tax gross-up in the amount of $437,575 to offset the taxes attributable to the portion of his equity award that was deferred pursuant to his Deferred Share Agreement. These amounts are disclosed under this table because they meet the definition of “nonqualified deferred compensation” under federal tax laws. These amounts, however, are also disclosed in the Summary Compensation Table under “All Other Compensation”. Please refer to the narrative under the Summary Compensation Table beginning on page 215 for a more detailed description of the tax gross-ups paid in connection with the Merger. Further, the amount reported under “Registrant Contributions in last FY” for Mr. Wilder includes a payment, which he received in January 2008, of $162,303 for office space through October 10, 2008. The amount reported under “Registrant Contributions in last FY” for Mr. Wilder also includes $141,823, which EFH Corp. will pay for secretarial assistance for Mr. Wilder through October 10, 2008.

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The amounts reported in the Nonqualified Deferred Compensation table also include deferrals and the company match under the Salary Deferral Program and earnings and distributions under the Salary Deferral Program and the Deferred and Incentive Compensation Plan. Amounts reported under the heading “Aggregate Earnings in Last FY” also include dividends paid after the vesting date on prior deferrals under the Long-Term Incentive Compensation Plan that were paid out in 2007. The amounts reported as “Executive Contributions in Last FY” are also included as “Salary” in the Summary Compensation Table on page 215. Amounts included in “Aggregate Balance at Last FYE” have been included in the Summary Compensation Table in prior years as follows for Messrs. Greene, $492,223; Campbell, $118,070; Poole, $319,704; McCall, $0; Burke $0; Wilder, $0 and Baker $540,617. The material terms of the Salary Deferral Program and the Deferred and Incentive Compensation Plan are described below.

Salary Deferral Program:Under EFH Corp.’s Salary Deferral Program each employee of EFH Corp. and its participating subsidiaries who is in a designated job level and whose annual salary is equal to or greater than an amount established under the Salary Deferral Program ($110,840 for the program year beginning January 1, 2007) 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; provided that employees who first became eligible to participate in the Salary Deferral Program on or after January 1, 2002, who were also eligible, or became eligible, to participate in the Deferred and Incentive Compensation Plan, were not eligible to receive any Salary Deferral Program matching awards during the period prior to the freezing of the Deferred and Incentive Compensation Plan on March 31, 2005.

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. The amount included in “Registrant Contributions in Last FY” attributable to EFH Corp.’s matching award under the Salary Deferral Program was for Messrs. Greene, $53,679; Campbell, $0; Poole, $24,560; McCall, $27,677; Burke, $27,417; Wilder, $75,000 and Baker, $42,899.

Deferred and Incentive Compensation Plan:In November 2004, the Board approved an amendment to the Deferred and Incentive Compensation Plan which froze any future participation as of March 31, 2005, which was the end of the 2004-2005 plan year for the Deferred and Incentive Compensation Plan. This amendment prohibited additional deferrals by existing participants and closed the plan to new participants. As amended, existing Deferred and Incentive Compensation Plan accounts will mature and be distributed in accordance with their normal schedule under the terms of the Deferred and Incentive Compensation Plan. The Plan was further restated and amended effective January 1, 2007 providing for the distribution of participant accounts as of the later of January 2, 2008 or the occurrence of a change in control (as defined in the plan).

For plan years beginning on or prior to April 1, 2004, participants in the Deferred and Incentive Compensation Plan were permitted to defer a percentage of their base salary not to exceed a maximum percentage determined by the Pre-Merger O&C Committee for each plan year and in any event not to exceed 15% of the participant’s base salary. EFH Corp. made a matching award equal to 150% of the participant’s deferred salary. Matching awards are subject to forfeiture under certain circumstances.

Deferrals and matching awards under the Deferred and Incentive Compensation Plan made after December 31, 2004, are subject to the provisions of Section 409A of the Internal Revenue Code. Accordingly, certain provisions of the Deferred and Incentive Compensation Plan have been modified in order to comply with the requirements of Section 409A and related guidance. The amount included in “Aggregate Balance at Last FYE” and attributable to the Deferred and Incentive Compensation Plan was for Messrs. Wilder, $0; Campbell, $0; Greene, $2,053,437; Baker, $4,545,177; Poole, $0; McCall, $1,019,352; and Burke, $0.

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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, 2007. Even though the Merger resulted in a change of control of EFH Corp. on October 10, 2007, the disclosure presented below under the heading “Without Cause or For Good Reason In Connection With Change in Control” reflects another change of control of EFH Corp. as of December 31, 2007.

Employment Arrangements with Contingent Payments:Messrs. Campbell, Poole and Burke each have employment agreements with change in control and severance provisions as described in the following tables. The change in control and severance terms included in the employment agreements will govern through their respective terms. As of December 31, 2007, Messrs. Greene and McCall did not have employment agreements. As of such date, however, Messrs. Greene and McCall would have been eligible to receive benefits in the event of a change in control or certain other termination events pursuant to the terms of EFH Corp.’s Change in Control Policy and Severance Plan as described in the following tables. A description of EFH Corp.’s Change in Control Policy and Severance Plan is set forth below. It is expected that Messrs. Greene and McCall will execute employment agreements with EFH Corp. in April 2008 that will include change in control and severance provisions. These provisions are expected to be consistent with the change in control and severance provisions contained in Mr. Burke’s employment agreement.

Change in Control Policy

EFH Corp.’s Change in Control Policy provides the payment of transition benefits to eligible executive officers who are not eligible for transition benefits pursuant to another plan or agreement (including an employment agreement) if:

1. their employment with EFH Corp. or a successor is terminated within twenty-four months following a change of control of EFH Corp. and

2. they:

a. are terminated without cause, or

b. resign for good reason due to a reduction in salary or a material reduction in the aggregate level or value of benefits for which they are eligible.

The terms “change of control,” “without cause” and “good reason” are defined in the Change in Control Policy which is an exhibit to EFH Corp.’s current report on Form 8-K filed May 23, 2005.

Executive officers that participate in the Change in Control Policy will be eligible to receive:

1. a one-time lump sum cash severance payment in an amount equal to two times the sum of the executive’s (a) annualized base salary and (b) annual target incentive award for the year of termination or resignation;

2. continued eligibility for distribution of already granted equity awards at maturity; however any such distribution will be prorated for the period of employment during the relevant performance or restriction period prior to termination;

3. continued coverage under our health care benefit plans for two years;

4. outplacement assistance at our expense for 18 months;

5. any vested, accrued benefits to which the executive is entitled under our employee benefits plans and

6. if any of the severance benefits described in the Change in Control Policy shall result in an excise tax pursuant to Code Sections 280G or 4999 of the Internal Revenue Code, payable by the executive, a tax gross-up payment to cover such additional taxes, but subject to a cut back to the Section 280G limit if the severance benefits are less than 110% of such limit.

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Severance Plan

EFH Corp.’s Severance Plan provides benefits to eligible executive officers who are not eligible for severance pursuant to another plan or agreement (including an employment agreement) and whose employment is involuntarily terminated for reasons other than:

1. cause (as defined in the Severance Plan);

2. the employee’s participation in our long-term disability plan or

3. a transaction involving the company or any of its affiliates in which the employee is offered employment with a company involved in, or related to, the transaction.

The Severance Plan is an exhibit to EFH Corp.’s current report on Form 8-K filed May 23, 2005.

Executive officers that participate in the Severance Plan will be eligible to receive:

1. a one-time lump sum cash severance payment in an amount equal to the sum of (a) two times the executive’s annualized base salary and (b) a prorated portion of the executive’s annual target incentive award for the year of termination;

2. continued coverage under the company’s health care benefit plans for two years;

3. outplacement assistance at the company’s expense for 18 months and

4. any vested accrued benefits to which the executive is entitled under the company’s employee benefits plans.

Mr. Wilder

On October 11, 2007, Mr. Wilder resigned for “good reason” as defined in his employment agreement. Under the terms of his Severance Agreement, EFH Corp. provided Mr. Wilder certain severance payments and other benefits, including, among other things: (i) a one-time cash severance payment equal to two times the sum of his base salary and target bonus under the Executive Annual Incentive Plan ($7,500,00); (ii) a one-time, pro-rated bonus consistent with the Executive Annual Incentive Plan based on actual company performance for 2007 in the amount of $2,083,333 as determined by the Pre-Merger O&C Committee prior to the closing of the Merger; (iii) payment or reimbursement for office space and secretarial assistance for one year and (iv) the establishment of a secular trust to hold certain amounts relating to EFH Corp.’s potential obligation to gross-up certain payments obligations of Mr. Wilder under Section 4999 and 409A of the Internal Revenue Code. Mr. Wilder and EFH Corp. and certain of its affiliates also agreed to a mutual release and waiver relating to Mr. Wilder’s employment by EFH Corp. In addition, as previously disclosed, EFH Corp. made the following distributions in favor of Mr. Wilder in respect of his previously awarded incentive compensation: (i) a single lump sum cash payment in the amount of $95,681,275 for Mr. Wilder’s 2005, 2006 and 2007 long-term incentive compensation awards; (ii) a cash payment in the amount of $44,821,603 for Mr. Wilder’s earned and vested long-term incentive awards that were deferred in 2006 and 2007; (iii) distribution of a vested and deferred special incentive equity-based compensation award in the amount of $76,161,803; and (iv) distribution of all other vested benefits or account balances (totaling approximately $3 million) under certain other of EFH Corp.’s employee benefit plans. Payment of the equity-based awards was based on the number of shares of EFH Corp.’s common stock payable pursuant to each such award multiplied by $69.25, the price per share paid in the Merger for EFH Corp.’s common stock, and distributed to Mr. Wilder by previously established rabbi trusts on January 2, 2008.

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Mr. Baker

In November 2007, Mr. Baker retired as Vice Chairman of EFH Corp. In connection with his retirement, Mr. Baker received certain payments and other benefits, including, a one-time, pro-rated bonus consistent with the Executive Annual Incentive Plan based on actual company performance for 2007 in the amount of $337,488. In addition, EFH Corp. made the following distributions in favor of Mr. Baker in respect of his previously awarded incentive compensation: (i) a single lump sum cash payment in the amount of $4,961,367 for Mr. Baker’s 2005 and 2006 long-term incentive compensation awards; (ii) a cash payment in the amount of $21,595,059 for Mr. Baker’s earned and vested long-term incentive awards that were deferred in 2002, 2003 and 2004 and (iii) distribution of all other vested benefits or account balances under certain other of EFH Corp.’s employee benefit plans. Payment of the equity-based awards was based on the number of shares of EFH Corp.’s common stock payable pursuant to each such award multiplied by $69.25, the price per share paid in the Merger for EFH Corp.’s common stock, and distributed to Mr. Baker by previously established rabbi trusts on January 2, 2008.

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1. Mr. Greene

Potential Payments to Mr. Greene Upon Termination (per company policy)

Benefit	Retirement		Voluntary		For Cause		Death		Disability		Without Cause		Without Cause Or For Good Reason In Connection With Change in Control
Cash Severance	$	0	$	0	$	0	$	0	$	0	$	1,787,500	$	2,275,000
Executive Annual Incentive Plan	$	487,500	$	0	$	0	$	487,500	$	487,500	$	0	$	0
-Supplemental Retirement Plan(1)	$	3,831,598	$	3,831,598	$	3,831,598	$	3,560,267	$	3,176,717	$	3,831,598	$	3,831,598
-Retiree Medical (2)	$	3,408	$	0	$	0	$	0	$	0	$	0	$	0
Deferred Compensation (3)
-Salary Deferral Program	$	0	$	0	$	0	$	0	$	0	$	0	$	0
-Deferred & Incentive Comp. Plan	$	0	$	0	$	0	$	0	$	0	$	0	$	0
Health & Welfare
-Medical/COBRA	$	0	$	0	$	0	$	0	$	0	$	14,005	$	14,005
-Life Insurance (4)	$	0	$	0	$	0	$	1,014,000	$	0	$	0	$	0
Other
-Outplacement Assistance	$	0	$	0	$	0	$	0	$	0	$	146,250	$	146,250
-Split-Dollar Life Insurance (5)	$	242,062	$	0	$	0	$	3,140,000	$	242,062	$	242,062	$	242,062
Totals	$	4,564,568	$	3,831,598	$	3,831,598	$	8,201,767	$	3,906,279	$	6,021,415	$	6,508,915

(1) Mr. Greene is fully vested in all retirement benefits as disclosed in the Pension Benefits table on page 221.

(2) Amount reported is the annual subsidy provided by EFH Corp.

(3) Amounts listed reflect the immediate vesting of EFH Corp. matching contribution due to the occurrence of a termination or change-in-control.

(4) Amount reported is death benefit.

(5) Amount reported, other than death benefit, is premiums for remaining 4 years.

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2. Mr. Campbell

Potential Payments to Mr. Campbell Upon Termination (per employment agreement)

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	$	611,200	$	611,200	$	833,912	$	1,833,600
Executive Annual Incentive Plan	$	0	$	0	$	229,200	$	229,200	$	0	$	0
Equity
-LTIP	$	0	$	0	$	5,540,000	$	5,540,000	$	5,540,000	$	5,540,000
Retirement Benefits
-Supplemental Retirement Plan (1)	$	84,208	$	84,208	$	84,208	$	126,389	$	84,208	$	84,208
Health & Welfare
-Medical/COBRA	$	0	$	0	$	15,624	$	0	$	15,801	$	15,801
-Dental/COBRA	$	0	$	0	$	1,676	$	0	$	1,675	$	1,675
-AD&D (2)	$	0	$	0	$	765,000	$	0	$	0	$	0
-LTD (3)	$	0	$	0	$	0	$	229,200	$	0	$	0
Other
-Excise Tax Gross-Ups	$	0	$	0	$	0	$	0	$	0	$	3,149,591
Totals	$	84,208	$	84,208	$	7,246,908	$	6,735,989	$	6,475,596	$	10,624,875

(1) Present value of accrued non-qualified pension. Amounts listed reflect the immediate vesting of retirement benefits due to the Retirement Plan being in a partial plan termination status.

(2) Payable only in the event of accidental death.

(3) Amount reported is the annual payable benefit.

Mr. Campbell’s employment agreement, as amended, 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 lump sum payment equal to his annualized base salary plus his target annual incentive;

b. a prorated annual incentive bonus for the year of termination;

c. payment of all outstanding long-term incentive awards at the times such awards would otherwise have been paid in accordance with their terms;

d. immediate grant of all ungranted long-term incentive awards that would have been made during the one year period following the date of his death or disability; and

e. certain continuing health care and company benefits.

2. In the event of Mr. Campbell’s termination without cause or resignation for good reason, Mr. Campbell would be eligible to receive the following payments and benefits:

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a. a lump sum cash payment equal to his base salary and the annual incentive bonuses he would have received through the remainder of the term of his employment agreement, with a minimum payment equal to the sum of his annualized base salary and annual incentive bonus;

b. payment of all ungranted long-term incentive awards that would have been made during the remainder of the term of his employment agreement in an amount equal to the per share Merger consideration ($69.25);

c. a cash payment equal to the forfeited portion of Mr. Campbell’s accounts under the Salary Deferral Program, and matching contributions that would have been made under the Salary Deferral Program during the 12-month period following the termination;

d. the additional retirement compensation as if Mr. Campbell had worked through the expiration of the term of his employment agreement; and

e. certain continuing health care and company benefits.

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., Mr. Campbell would be eligible to receive the following payments and benefits:

a. a lump sum cash payment equal to his base salary and the annual incentive bonuses he would have received through the remainder of the term of his employment agreement, with a minimum payment equal to three times the sum of his annualized base salary and annual incentive bonus;

b. payment of all ungranted long-term incentive awards that would have been made during the remainder of the term of his employment agreement in an amount equal to the per share Merger consideration ($69.25);

c. a cash payment equal to the forfeited portion of Mr. Campbell’s accounts under the Salary Deferral Program, and matching contributions that would have been made under the Salary Deferral Program during the 24-month period following the termination;

d. the additional retirement compensation as if Mr. Campbell had worked through the expiration of the term of his employment agreement;

e. certain continuing health care and company benefits; and

f. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

On October 10, 2007, EFH Corp. entered into an Additional Payment Agreement with Mr. Campbell, pursuant to which EFH Corp. has agreed, among other things, to establish a secular trust to hold certain amounts relating to EFH Corp.’s obligation to gross-up certain payments to Mr. Campbell, which may be subject to excise taxes under Section 4999 of the Internal Revenue Code.

On September 28 and October 4, 2007, Mr. Campbell’s employment agreement was amended to address the following matters related to the Merger, among other things: (i) that a termination of employment by Mr. Campbell for any reason during the thirty day period commencing on the sixth month anniversary of the consummation of the Merger shall be deemed a termination for “good reason” (as defined in the employment agreement); (ii) that the value of Mr. Campbell’s long-term incentive compensation awards will be based on the per share consideration received by EFH Corp.’s shareholders in the Merger; (iii) for the payment to Mr. Campbell of his 2005, 2006 and 2007 long-term incentive compensation awards on January 2, 2008; and (iv) clarification that in the event Mr. Campbell’s employment with EFH Corp. is terminated for “good reason” or without “cause” following the Merger, the value of any of Mr. Campbell’s then ungranted 2008 and 2009 long-term incentive compensation awards will be paid in cash in a single lump sum payment (based on 40,000 performance units for each of 2008 and 2009 multiplied by the $69.25 price per share paid by in the Merger) on the later of the date of such termination and January 2, 2008.

During the term of Mr. Campbell’s employment agreement, severance benefits and change in control benefits provided pursuant to his employment agreement are in lieu of, and not in addition to, severance benefits and change in control benefits under EFH Corp.’s severance and change in control policies.

230

3. Mr. Poole

Potential Payments to Mr. Poole Upon Termination (per employment agreement)

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	$	491,200	$	491,200	$	652,691	$	982,400
Executive Annual Incentive Plan	$	0	$	0	$	184,200	$	184,200	$	0	$	0
Equity
-LTIP	$	0	$	0	$	4,155,000	$	4,155,000	$	4,155,000	$	4,155,000
Retirement Benefits
-Supplemental Retirement Plan (1)	$	63,556	$	63,556	$	63,556	$	71,729	$	63,556	$	63,556
Deferred Compensation (2)
-Salary Deferral Program	$	0	$	0	$	6,070	$	6,070	$	6,070	$	6,070
Health & Welfare
-Medical/COBRA	$	0	$	0	$	15,840	$	0	$	15,778	$	15,778
-Dental/COBRA	$	0	$	0	$	1,676	$	0	$	1,675	$	1,675
-Life Insurance (3)	$	0	$	0	$	308,000	$	0	$	0	$	0
-AD&D (4)	$	0	$	0	$	615,000	$	0	$	0	$	0
-LTD (5)	$	0	$	0	$	0	$	153,504	$	0	$	0
Other
-Excise Tax Gross-Ups	$	0	$	0	$	0	$	0	$	0	$	2,232,934
Totals	$	63,556	$	63,556	$	5,840,542	$	5,061,703	$	4,894,770	$	7,457,413

(1) Present value of accrued non-qualified pension. Amounts listed reflect the immediate vesting of retirement benefits due to the TXU Retirement Plan being in a partial plan termination status.

(2) Amounts listed reflect the immediate vesting of EFH Corp. matching contribution due to the occurrence of a termination or change-in-control. These amounts are also included in the Nonqualified Deferred Compensation table on page 223.

(3) Amount reported is death benefit.

(4) Payable only in the event of accidental death.

(5) Annual payable benefit.

Mr. Poole’s employment agreement, as amended, provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1. In the event of Mr. Poole’s death or disability:

a. a lump sum payment equal his annualized base salary plus his target annual incentive;

b. a prorated annual incentive bonus for the year of termination;

c. payment of all outstanding long-term incentive awards at the times such awards would otherwise have been paid in accordance with their terms;

d. immediate grant of all ungranted long-term incentive awards that would have been made during the one year period following the date of his death or disability; and

e. certain continuing health care and company benefits.

2. In the event of Mr. Poole’s termination without cause or resignation for good reason, Mr. Poole would be eligible to receive the following payments and benefits:

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a. a lump sum cash payment equal to his base salary and the annual incentive bonuses he would have received through the remainder of the term of his employment agreement, with a minimum payment equal to the sum of his annualized base salary and annual incentive bonus;

b. payment of all ungranted long-term incentive awards that would have been made during the remainder of the term of his employment agreement in an amount equal to the per share Merger consideration ($69.25);

c. a cash payment equal to the forfeited portion of Mr. Poole’s accounts under the Salary Deferral Program, and matching contributions that would have been made under the Salary Deferral Program during the 12-month period following the termination;

d. the additional retirement compensation as if Mr. Poole had worked through the expiration of the term of his employment agreement; and

e. certain continuing health care and company benefits.

3. In the event of Mr. Poole’s termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp., Mr. Poole would be eligible to receive the following payments and benefits:

a. a lump sum cash payment equal to his base salary and the annual incentive bonuses he would have received through the remainder of the term of his employment agreement, with a minimum payment equal to two times the sum of his annualized base salary and annual incentive bonus;

b. payment of all ungranted long-term incentive awards that would have been made during the remainder of the term of his employment agreement in an amount equal to the per share Merger consideration ($69.25);

c. a cash payment equal to the forfeited portion of Mr. Poole’s accounts under the Salary Deferral Program, and matching contributions that would have been made under the Salary Deferral Program during the 24-month period following the termination;

d. the additional retirement compensation as if Mr. Poole had worked through the expiration of the term and his employment agreement;

e. certain continuing health care and company benefits; and

f. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

On October 10, 2007, EFH Corp. entered into an Additional Payment Agreement with Mr. Poole, pursuant to which EFH Corp. has agreed, among other things, to establish a secular trust to hold certain amounts relating to EFH Corp.’s obligation to gross-up certain payments to Mr. Poole, which may be subject to excise taxes under Section 4999 of the Internal Revenue Code.

On September 28 and October 4, 2007, Mr. Poole’s employment agreement was amended to address the following matters related to the Merger, among other things: (i) that a termination of employment by Mr. Poole for any reason during the thirty day period commencing on the sixth month anniversary of the consummation of the Merger shall be deemed a termination for “good reason” (as defined in the employment agreement); (ii) that the value of Mr. Poole’s long-term incentive compensation awards will be based on the per share consideration received by EFH Corp.’s shareholders in the Merger; (iii) for the payment to Mr. Poole of his 2005, 2006 and 2007 long-term incentive compensation awards on January 2, 2008; and (iv) clarification that in the event Mr. Poole’s employment with EFH Corp. is terminated for “good reason” or without “cause” following the Merger, the value of any of Mr. Poole’s then ungranted 2008 and 2009 long-term incentive compensation awards will be paid in cash in a single lump sum payment on the later of the date of such termination and January 2, 2008.

On January 2, 2008, Mr. Poole’s employment agreement was amended to provide that EFH Corp. would pay Mr. Poole the following lump sum cash payments on or before January 15, 2008: (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 Mr. Poole’s ungranted 2008 and 2009 equity awards under his employment agreement (based on 30,000 performance units for each of 2008 and 2009 multiplied by the price per share paid by in the Merger). Mr. Poole agreed that the payment of such amounts represents full and final payment for the cash severance and ungranted equity awards provided for under his employment agreement. Pursuant to the terms of the amendment, Mr. Poole will have no right to any payment under EFH Corp.’s bonus plans for calendar year 2008 nor will he have the right to participate in any of EFH Corp.’s equity-based compensation programs.

During the term of Mr. Poole’s employment agreement, severance benefits and change in control benefits provided pursuant to his employment agreement are in lieu of, and not in addition to, severance benefits and change in control benefits under our severance and change in control policies.

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4. Mr. McCall

Potential Payments to Mr. McCall Upon Termination (per EFH Corp. policy)

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	$	1,375,000	$	1,750,000
Executive Annual Incentive Plan	$	0	$	0	$	375,000	$	375,000	$	0	$	0
Retirement Benefits
-Supplemental Retirement Plan (1)	$	528,839	$	528,839	$	471,577	$	472,783	$	528,839	$	528,839
Deferred Compensation (2)
-Salary Deferral Program	$	0	$	0	$	9,348	$	9,348	$	0	$	9,348
Health & Welfare
-Medical/COBRA	$	0	$	0	$	0	$	0	$	21,068	$	21,068
-Dental/COBRA	$	0	$	0	$	0	$	0	$	2,233	$	2,233
-Life Insurance (3)	$	0	$	0	$	1,951,000	$	0	$	0	$	0
-AD&D (4)	$	0	$	0	$	1.301,000	$	0	$	0	$	0
-LTD (5)	$	0	$	0	$	0	$	195,000	$	0	$	0
Other
-Outplacement Assistance	$	0	$	0	$	0	$	0	$	112,500	$	112,500
-Split-Dollar Life Insurance (6)					$	900,000	$	37,823	$	37,823	$	37,823
Totals	$	528,839	$	528,839	$	5,007,925	$	1,089,954	$	2,077,463	$	2,461,811

(1) Mr. McCall is fully vested in all retirement benefits as disclosed in the Pension Benefits table on page 221.

(2) Amounts listed reflect the immediate vesting of EFH Corp. matching contribution due to the occurrence of a termination or change-in-control.

(3) Amount reported is death benefit.

(4) Payable only in the event of accidental death.

(5) Amount reported is the annual payable benefit.

(6) Amount reported, other than death benefit, is premiums for remaining 4 years.

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5. Mr. Burke

Potential Payments to Mr. Burke Upon Termination (per employment agreement)

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					$	450,000	$	450,000	$	2,100,000	$	2,100,000
Executive Annual Incentive Plan	$	0	$	0	$	450,000	$	450,000	$	0	$	0
Retirement Benefits
-Supplemental Retirement Plan (1)	$	17,401	$	17,401	$	19,887	$	36,988	$	17,401	$	17,401
Deferred Compensation (2)
-Salary Deferral Program	$	0	$	0	$	10,765	$	10,765	$	0	$	10,765
Health & Welfare
-Medical/COBRA	$	0	$	0	$	0	$	0	$	20,616	$	20,616
-Dental/COBRA	$	0	$	0	$	0	$	0	$	2,188	$	2,188
Other
-Excise Tax Gross-Ups											$	793,707
Totals	$	17,401	$	17,401	$	930,652	$	947,753	$	2,140,205	$	2,944,677

(1) Present value of benefit

(2) Amounts listed reflect the immediate vesting of EFH Corp. matching contribution due to the occurrence of a termination or change-in-control.

Mr. Burke entered into an employment agreement effective December 31, 2007 which 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 options, if any, to which Mr. Burke may be entitled.

2. In the event of Mr. Burke’s termination without cause or resignation for good reason, Mr. Burke would be eligible to receive the following payments and benefits:

a. a lump sum payment equal to two times the sum of: (1) his annualized base salary and (2) his annual incentive target;

b. payment of employee benefits, including stock options, 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., Mr. Burke would be eligible to receive the following payments and benefits:

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 options, 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.

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On October 10, 2007, we entered into an Additional Payment Agreement with Mr. Burke, pursuant to which EFH Corp. has agreed, among other things, to establish a secular trust to hold certain amounts relating to EFH Corp.’s obligation to gross-up certain payments to Mr. Burke related to the Merger, which may be subject to excise taxes under Section 4999 of the Internal Revenue Code.

During the term of Mr. Burke’s employment agreement, severance benefits and change in control benefits provided pursuant to his employment agreement are in lieu of, and not in addition to, severance benefits and change in control benefits under EFH Corp.’s severance and change in control policies.

Excise Tax Gross-Ups

Executive Officers Covered by Employment Agreements:Pursuant to their employment agreements, EFH Corp. agreed to reimburse Messrs. Wilder, Campbell, Burke, and Poole (“the executives”) for all excise (and other special additional) taxes that are imposed on them in connection with a change in control, including those imposed under Code section 4999, and any income and excise taxes that are payable by the executive as a result of any such reimbursements.

The “Excise Tax Gross-Up” amount in the tables above assumes that the executive is entitled to a full reimbursement of the following expenses from EFH Corp.:

1. Any excise taxes that are imposed upon the executive as a result of the change in control;

2. Any income and excise taxes imposed upon the executive as a result of EFH Corp.’s reimbursement of the excise tax amount; and

3. Any additional income and excise taxes that are imposed upon the executive as a result of EFH Corp.’s reimbursement for any excise or income taxes.

The calculation is based upon Internal Revenue Code Section 4999, which provides for an excise tax rate of 20%, and assumes a 35% federal income tax rate, a 1.45% Medicare tax rate and a 0% state income tax rate. The executives reside in the state of Texas, which does not impose a state income tax. For purposes of the Code Section 280G calculation it is assumed that no amounts will be discounted as attributable to reasonable compensation and no value will be attributed to the executive executing a non-competition agreement.

The Excise Tax Gross-Up is payable to the executive officer for any excise tax incurred regardless of whether his employment is terminated. However, the actual amount of any Excise Tax Gross-Up will change based upon whether the executive’s employment with EFH Corp. is terminated because the amount of compensation received by the executive officer, and therefore subject to Internal Revenue Code Section 280G, will change. The Excise Tax Gross-Up was calculated assuming (1) that a change in control occurred on December 31, 2007, and (2) that the executive officer’s employment terminated on that same day. In addition, to the extent that any payout was conditioned upon or determined based on achievement of performance criteria, it was assumed that such payout would be at target level of performance, which was 100%. Further, for Messrs. Campbell and Poole, the amounts of the Excise Tax Gross-Up attributable to any ungranted 2008 and 2009 equity awards provided for under the terms of their respective employment agreements were calculated assuming that the executives would receive cash payments equal to the number of performance units issuable for 2008 and 2009 multiplied by the per share Merger Consideration ($69.25). It was also assumed that all payments will be made in a manner that complies with Internal Revenue Code section 409A.

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Director Compensation

The table below sets forth information regarding the aggregate compensation paid to the members of the current and former board of directors during the fiscal year ended December 31, 2007. Directors who are officers, or former officers, of EFH Corp. do not receive any fees for service as a director. EFH Corp. reimburses some directors for certain reasonable expenses incurred in connection with their services as directors.Prior to the decision to discontinue owning and operating aircraft, directors were permitted to use company aircraft for travel related to their services as directors.

Director Compensation

Name	Fees Earned or Paid in Cash ($)	Stock Awards ($)	All Other Compensation ($)	Total ($)
David Bonderman (1)	n/a	n/a	n/a	n/a
Donald L. Evans (1)	1,500,000	0	0	1,500,000
Frederick M. Goltz (1)	n/a	n/a	n/a	n/a
James R. Huffines (1)	37,500	0	56,250	93,750
Scott Lebovitz (1)	n/a	n/a	n/a	n/a
Jeffrey Liaw (1)	n/a	n/a	n/a	n/a
Marc S. Lipschultz (1)	n/a	n/a	n/a	n/a
Michael MacDougall (1)	n/a	n/a	n/a	n/a
Lyndon L. Olson, Jr. (1)	37,500	0	56,250	93,750
Kenneth Pontarelli (1)	n/a	n/a	n/a	n/a
William K. Reilly (1)	37,500	0	0	37,500
Jonathan D. Smidt (1)	n/a	n/a	n/a	n/a
William Young (1)	n/a	n/a	n/a	n/a
Kneeland Youngblood (1)	37,500	0	0	37,500
Leldon E. Echols (2)	207,500	100,000	0	307,500
Steven Feldman (3)	n/a	n/a	n/a	n/a
Kerney Laday (2)	98,000	100,000	0	198,000
Jack E. Little (2)	210,500	100,000	0	310,500
Gerardo I. Lopez (2)	88,500	100,000	0	188,500
J. E. Oesterreicher (2)	160,500	100,000	0	260,500
Michael W. Ranger (2)	205,000	100,000	0	305,000
Leonard H. Roberts (2)	154,500	100,000	0	254,500
Glenn F. Tilton (2)	184,500	100,000	0	284,500
E. Gail de Planque (2)	21,250	100,000	0	121,250

(1) The EFH Corp. Board of Directors, except for Mr. Evans, did not actually receive any payments in 2007 for their services as directors as all annual fees are paid quarterly in arrears with the first cash payment and the first equity awarded in 2008 for services provided in 2007. Messrs. Huffines, Olson, Reilly and Youngblood receive $150,000 annually and an annual equity award valued at $100,000. Directors who are employed by the Sponsor Group (or their respective affiliates) do not receive compensation for service as directors.

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It is currently expected that in April 2008, EFH Corp. will enter into a consulting agreement with Mr. Evans, pursuant to which he would receive the following compensation:

1. An annual fee of $2,000,000;

2. 200,000 shares of restricted stock 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 is also expected to acknowledge that Mr. Evans was previously paid a cash fee of $1,500,000 for his services to the Sponsor Group in connection with the Merger. The consulting agreement is expected to have a term running through October 10, 2009, subject to extension upon mutual agreement of up to three additional years.

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 2007 are reflected above in the “All Other Compensation” column.

It is anticipated that in April 2008, Messrs. Evans, Huffines, Olson, Reilly and Youngblood will be given the opportunity to purchase shares of EFH Corp.’s common stock at a price of $5.00 per share and that Messrs. Huffines, Olson and Reilly will each be granted 120,000 shares of EFH Corp.’s common stock at a price of $5.00 per share. In connection with these purchases and with their grants of equity, these directors are expected to enter into stockholder agreements and sale participation agreements with EFH Corp. The stockholder agreements will 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 will be 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.

(2) All former TXU Corp. directors resigned in October 2007 following the Merger. During 2007, each former TXU Corp. director received an annual board retainer of $45,000 plus $1,500 for each meeting attended. In addition, each former committee member received $1,500 for each committee meeting attended. Non-chair members of the Audit Committee and the Nuclear Committee received an annual fee of $5,000 and the chairs of the Audit Committee and the Nuclear Committee received an annual fee of $10,000. The chairs of other committees received an annual fee of $5,000. In addition, each member of the Strategic Transaction Committee (other than the chairman) received a fee of $100,000. The chairman of the Strategic Transaction Committee received a fee of $125,000. Amounts reported include amounts deferred under EFH Corp.’s Deferred Compensation Plan for Outside Directors, as disclosed below.

During 2007, each former director received an annual grant of EFH Corp.’s common stock with a market value equal to $100,000 which is also the SFAS 123R value of these grants. Amounts reported include amounts deferred under the Deferred Compensation Plan for Outside Directors. Former directors who received a retainer for their board service could elect to defer, in increments of 25%, all or a portion of their annual board retainer and equity grant under the Deferred Compensation Plan for Outside Directors. Under the Deferred Compensation Plan for Outside Directors, a trustee purchased EFH Corp.’s common stock with an amount of cash equal to each participant’s deferred retainer and equity grant. The trustee established accounts for each participant containing performance units equal to such number of shares of EFH Corp.’s common stock. Each year, the participant selected a maturity period between three and ten years for that year’s deferrals. On the expiration of the applicable maturity period or upon a director’s death or disability, the trustee distributes the director’s maturing accounts in cash based on the then current value of the performance units. In February 2006, certain provisions of the Deferred Compensation Plan for Outside Directors were modified to comply with the requirements of Section 409A and related guidance. Upon the closing of the Merger in October 2007, the directors’ accounts under the Deferred Compensation Plan for Outside Directors were liquidated, proceeds were invested in a money market fund and the balances were paid to directors in January 2008. The market value at December 31, 2007 of such accounts was for Mr. Echols $192,446; Mr. Laday $542,073; Dr. Little $2,199,910; Mr. Oesterreicher $1,817,507; Mr. Ranger $1,634,507; Mr. Roberts $268,225; Mr. Tilton $393,323 and Dr. de Planque $54,091.

(3) Mr. Feldman served as a director on the EFH Corp. board from October 10, 2007 until October 16, 2007.

EFH Corp. has implemented a scholarship funding program to honor retiring directors. Upon a director’s retirement from the Board, EFH Corp. will fund two scholarships at a public university in a state where EFH Corp. does business, designated by the retiring director. The time period of such funding is equal to the number of years the retiring director served on the Board, up to a maximum of 20 years. The amount of each scholarship is the university’s then-current annual tuition (two semesters or the equivalent) for Texas residents plus course fees and books, up to an aggregate maximum of $9,000. EFH Corp. will fund scholarships beginning in 2008 for those directors that retired from the Board in connection with the Merger.

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

The following table presents information concerning stock-based compensation plans as of December 31, 2007. (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	19,514,000	$	5.00	52,486,000
	19,514,000	$	5.00	52,486,000

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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 March 28, 2008.

Name	Number of Shares Beneficially Owned	Percent of Class
Texas Energy Future Holdings Limited Partnership (1)	1,657,600,000	99.45	%
David Bonderman (2)	1,657,600,000	99.45	%
Donald L. Evans	—	—
Frederick M. Goltz (3)	1,657,600,000	99.45	%
James R. Huffines	—	—
Scott Lebovitz (4)	1,657,600,000	99.45	%
Jeffrey Liaw (2)	1,657,600,000	99.45	%
Marc S. Lipschultz (3)	1,657,600,000	99.45	%
Michael MacDougall (2)	1,657,600,000	99.45	%
Lyndon L. Olson, Jr.	—	—
Kenneth Pontarelli (4)	1,657,600,000	99.45	%
William K. Reilly	—	—
Jonathan D. Smidt (3)	1,657,600,000	99.45	%
John F. Young	600,000	*
William Young (4)	1,657,600,000	99.45	%
Kneeland Youngblood	—	—
M. S. Greene (5)	600,000	*
David A. Campbell	—	—
David P. Poole	—	—
Robert C. Walters	—	—
Michael T. McCall (5)	600,000	*
James A. Burke (5)	450,000	*
C. John Wilder	—	—
T. L. Baker	—	—
All directors and current executive officers as a group (25 persons)	1,659,850,000	99.60	%

* 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) 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

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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, Messr. 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 and executives of TPG Capital, L.P. 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.

(3) 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. 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.

(4) 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. Lebovitz, Pontarelli and Young 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. Lebovitz, Pontarelli and William Young may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Lebovitz, Pontarelli and William Young 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.

(5) Amounts included represent 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 by the company or a change in control of the company.

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

Policies and Procedures Relating to Related Party Transactions

The Code of Conduct provides that EFH Corp. employees are expected to avoid conflicts of interest between their personal interests and those of EFH Corp. The Code of Conduct requires employees or members of their immediate families not to:

1. receive compensation from, or have any financial interest in, a current or prospective supplier, customer, or competitor if that compensation or financial interest constitutes a conflict of interest for the employee, or

2. own a significant financial interest in any business that supplies EFH Corp. with a substantial amount of goods or services or where sales to EFH Corp. are a substantial part of the other business’s revenues.

With respect to the related person transactions described below, the various agreements between EFH Corp. and the other parties thereto were approved by either the Board of Directors or its Executive Committee.

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 (c) 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. It is expected that in April 2008, certain other executive officers and directors of EFH Corp. will become parties to this agreement.

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Management Services 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. 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. EFH Corp. paid $8 million under terms of the Management Agreement to the Sponsor Group in the period from October 11, 2007 to December 31, 2007.

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, (v) any breach or alleged breach of fiduciary duty as a director or officer of any member of the Company Group.

Sale Participation Agreement

In January 2008, John F. Young entered into, and in April 2008, M. S. Greene, James Burke and Michael McCall and certain directors are expected to enter into, sale participation agreements with EFH Corp. in connection with their purchase of EFH Corp.’s common stock. Pursuant to the terms of these 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.

Certain Charter Provisions

EFH Corp.’s restated certificate of formation contains provisions limiting directors’ obligations in respect of corporate opportunities.

Management Stockholders’ Agreement

Subject to a management stockholders’ agreement, certain members of management, including John F. Young, and expected to include M.S. Greene, James A. Burke and Michael T. McCall, along with 115 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 aggregate amount of this investment to date is approximately $31 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.

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Director Stockholders’ Agreement

In April 2008, certain members of our Board are expected to enter into a stockholders’ agreement with EFH Corp. See Item 11. Executive Compensation “Director Compensation”.

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. and the Predecessor in 2007 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, and

d. internal control reviews.

2. Tax related services, including:

a. tax compliance;

b. general tax consultation and planning, and

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

3. Other services, including:

a. process improvement, review and assurance;

b. litigation and rate case assistance;

c. general research;

d. forensic and investigative services, and

e. training services.

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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, 2007 and 2006, fees billed to EFH Corp. by Deloitte & Touche were as follows:

	2007		2006
Audit Fees. Fees for services necessary to perform the annual audit, review SEC filings, fulfill statutory and other service requirements, provide comfort letters and consents	$	6,562,000	$	6,227,000
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		5,804,000		5,176,000
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		1,043,000		253,000
All Other Fees.Fees for services including process improvement reviews, forensic accounting reviews, litigation and rate case assistance, and training services		80,000		286,000
Total	$	13,489,000	$	11,942,000

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PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Schedule I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

ENERGY FUTURE HOLDINGS CORP. (PARENT)

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF INCOME (LOSS)

(Millions of Dollars)

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007
							Year Ended December 31,
							2006			2005
Costs and expenses:
Selling, general and administrative expenses	$	17		$	58		$	70		$	71
Franchise and revenue-based taxes		1			—			1			—
Other income		—			(8	)		(15	)		(1	)
Other deductions		54			108			7			(26	)
Interest income		(54	)		(133	)		(74	)		(117	)
Interest expense and related charges		234			566			609			412
Total costs and expenses		252			591			598			339
Loss from continuing operations before income taxes and equity method investments		(252	)		(591	)		(598	)		(339	)
Income tax benefit		(533	)		(235	)		(214	)		(120	)
Equity earnings (loss) of subsidiaries		(1,641	)		1,077			2,936			1,931
Income (loss) from continuing operations		(1,360	)		721			2,552			1,712
Income from discontinued operations, net of tax effect		—			2			—			10
Net income (loss)	$	(1,360	)	$	723		$	2,552		$	1,722
Preference stock dividends		—			—			—			10
Net income (loss) available for common stock	$	(1,360	)	$	723		$	2,552		$	1,712

See Notes to Financial Statements.

245

ENERGY FUTURE HOLDINGS CORP. (PARENT)

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007
							Year Ended December 31,
							2006			2005
Cash flows — operating activities
Net income (loss)	$	(1,360	)	$	723		$	2,552		$	1,722
Income from discontinued operations, net of tax effect		—			(2	)		—			(10	)
Income (loss) from continuing operations		(1,360	)		721			2,552			1,712
Adjustments to reconcile income (loss) from continuing operations to cash provided by operating activities:
Equity in (earnings) losses of subsidiaries		1,641			(1,077	)		(2,936	)		(1,931	)
Deferred income tax expense (benefit) – net		(357	)		(67	)		116			17
Impairments and other asset writedown charges		1			68			—			—
Other, net		1			20			6			12
Net change in operating assets and liabilities		244			1,464			482			322
Cash provided by operating activities from continuing operations		170			1,129			220			132
Cash flows — financing activities
Issuances of securities:
Equity financing from Sponsor Group		8,236			—			—			—
Merger-related debt financing		9,000			—			—			—
Common stock		—			1			180			84
Retirements/repurchases of securities:
Merger-related debt repurchases		(5,522	)		—			—			—
Other long-term debt		—			(1	)		(911	)		(106	)
Preference stock		—			—			—			(300	)
Common stock		—			(13	)		(960	)		(1,137	)
Cash dividends paid:
Common stock		—			(788	)		(764	)		(544	)
Preference stock		—			—			—			(11	)
Change in advances – affiliates		33			50			1,724			1,883
Other, net		(400	)		(93	)		(12	)		(26	)
Cash provided by (used in) financing activities from continuing operations		11,347			(844	)		(743	)		(157	)
Cash flows — investing activities
Acquisition of EFH Corp		(32,694	)		—			—			—
Contribution from subsidiaries		21,000			—			—			—
Capital expenditures		(2	)		(70	)		(12	)		—
Investments in collateral trust		—			—			533			—
Other		(3	)		(1	)		2			16
Cash provided by (used in) investing activities from continuing operations		(11,699	)		(71	)		523			16
Discontinued operations:
Cash used in operating activities		—			—			—			(3	)
Cash used in financing activities		—			—			—			—
Cash used in investing activities		—			—			—			—
Cash used in discontinued operations		—			—			—			(3	)
Net change in cash and cash equivalents		(182	)		214			—			(12	)
Cash and cash equivalents — beginning balance		214			—			—			12
Cash and cash equivalents — ending balance	$	32		$	214		$	—		$	—

See Notes to Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. (PARENT)

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(Millions of Dollars)

	Successor		Predecessor
	December 31, 2007		December 31, 2006
ASSETS
Current assets:
Cash and cash equivalents	$	32	$	—
Advances to affiliates		378		—
Trade accounts receivable — net		27		5
Income taxes receivable		—		165
Commodity and other derivative contractual assets		3		2
Other current assets		253		8
Total current assets		693		180
Investments		15,157		12,457
Property, plant and equipment — net		—		33
Notes receivable from affiliates		12		12
Commodity and other derivative contractual assets		—		11
Accumulated deferred income taxes		477		118
Other noncurrent assets		146		150
Total assets	$	16,485	$	12,961
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Advances from affiliates	$	—	$	2,402
Long-term debt due currently (Note 2)		200		—
Trade accounts payable — nonaffiliates		6		18
Accounts payable to affiliates		111		102
Notes payable to affiliates		25		1,500
Commodity and other derivative contractual liabilities		38		21
Accumulated deferred income taxes		68		5
Other current liabilities		670		236
Total current liabilities		1,118		4,284
Commodity and other derivative contractual liabilities		—		63
Notes or other liabilities due affiliates		2,019		2,714
Long-term debt, less amounts due currently (Note 2)		6,289		3,643
Other noncurrent liabilities and deferred credits		374		117
Total liabilities		9,800		10,821
Shareholders’ equity		6,685		2,140
Total liabilities and shareholders’ equity	$	16,485	$	12,961

See Notes to Financial Statements.

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ENERGY FUTURE HOLDINGS CORP. (PARENT)

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO CONDENSED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

The accompanying unconsolidated condensed balance sheet, statements of income (loss) and cash flows present results of operations and cash flows of EFH Corp. (Parent) for periods preceding the Merger (Predecessor) and of EFH Corp. (Parent) for periods subsequent to the Merger (Successor). The financial statements of the Successor reflect the application of purchase accounting and include the activities of Merger Sub, all of which related to the acquisition of EFH Corp. Certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules of the SEC. Because the unconsolidated condensed financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the financial statements and related notes of Energy Future Holdings Corp. and Subsidiaries included in Item 8 of this Form 10-K. EFH Corp.’s subsidiaries have been accounted for under the equity method. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

2. LONG-TERM DEBT

At December 31, 2007 and 2006, the long-term debt of EFH Corp. (Parent) consisted of the following:

	Successor			Predecessor
	December 31, 2007			December 31, 2006
10.875% Fixed Senior Notes due November 1, 2017	$	2,000		$	—
11.25 / 12.00% Senior Toggle Notes due November 1, 2017		2,500			—
6.375% Fixed Senior Notes Series C due January 1, 2008 (a)		200			200
4.800% Fixed Senior Notes Series O due November 15, 2009 (b)		3			1,000
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
6.743% Floating Convertible Senior Notes due July 15, 2033 (c)		—			25
Fair value adjustments related to interest rate swaps		—			(73	)
Unamortized discount		—			(9	)
Unamortized fair value discount (d)		(714	)		—
Total EFH Corp.		6,489			3,643
Less amount due currently		(200	)		—
Total long-term debt	$	6,289		$	3,643

(a) Interest rates swapped to variable on entire principal amount at December 31, 2007.

(b) EFH Corp. commenced offers to purchase and consent solicitations for this series on September 25, 2007. EFH repurchased the majority of the bonds in October 2007.

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(c) Interest rates in effect at December 31, 2007. In conjunction with the Merger, a supplemental indenture was executed and provided that this series become payable in cash. On October 25, 2007, substantially all of these notes were converted and redeemed.

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

Maturities — Long-term debt maturities as of December 31, 2007 are as follows:

Year
2008	$	200
2009		3
2010		—
2011		—
2012		—
Thereafter		7,000
Unamortized fair value discount		(714	)
Total	$	6,489

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3. GUARANTEES

As discussed below, EFH Corp. (Parent) has 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. (Parent) agreed to indemnify Atmos Energy Corporation for certain qualified environmental claims arising in relation to the assets acquired by Atmos Energy Corporation. This environmental indemnity expired on October 1, 2007. In addition, until October 1, 2014, EFH Corp. (Parent) agreed to indemnify Atmos Energy Corporation 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 Energy Corporation, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximum aggregate amount that EFH Corp. (Parent) may be required to pay is $1.9 billion. To date, EFH Corp. (Parent) has not been required to make any payments to Atmos Energy Corporation under any of these indemnity obligations, and no such payments are currently anticipated.

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. 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, 2007, the balance of the indebtedness on EFC Holdings’ balance sheet was $114 million with maturities of principal and interest extending to December 2021. The indebtedness is secured by a lien on the purchased facilities. EFH Corp. (Parent) has guaranteed EFC Holdings’ obligation under this agreement.

4. DIVIDEND RESTRICTIONS

The indenture governing the EFH Corp. (Parent) Senior Cash-Pay and Toggle Notes (see Note 2) includes covenants that, among other things and subject to certain exceptions, restrict EFH Corp.’s (Parent) ability to pay dividends or make other distributions in respect of its capital stock.

EFH Corp. (Parent) received dividends from its consolidated subsidiaries totaling $1.461 billion, $1.198 billion and $525 million for the period from January 1, 2007 through October 10, 2007 and the years ended December 31, 2006 and 2005, respectively.

5. SUPPLEMENTAL CASH FLOW INFORMATION

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31,
							2006			2005
Cash payments (receipts) related to continuing operations:
Interest	$	179		$	512		$	607		$	403
Income taxes		(37	)		(310	)		(153	)		(120	)
Noncash investing and financing activities:
Noncash construction expenditures (a)		—			2			5			—
Noncash capital contribution from Texas Holdings		23			—			—			—

(a) Represents end-of-period accruals.

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(b) Exhibits:

EFH Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2007

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 8-K (filed October 11, 2007)	3.2	—	Amended and Restated Bylaws of Energy Future Holdings Corp., dated October 10, 2007
(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(ff)	—	Indenture, dated as of January 1, 1998, relating to Energy Future Holdings Corp.’s 6.375% Series C Exchange Notes
4(b)	1-12833 Form 10-K (1997) (filed March 27, 1998)	4(hh)	—	Officer’s Certificate establishing the terms of Energy Future Holdings Corp.’s Series C Exchange Notes
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. 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(d)	1-12833 Form 10-K (2005) (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
4(e)	1-12833 Form 10-K (2005) (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(f)	1-12833 Form 10-K (2005) (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

251

Exhibits	Previously Filed* With File Number	As Exhibit
4(g)	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(h)	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, as Trustee
4(i)	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
4(j)	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(k)	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(l)	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, as Trustee
4(m)	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% Debentures due 2022
	Texas Competitive Electric Holdings Company LLC
4(n)	333-108876 Form S-4 (filed September 17, 2003)	4(a)	—	Indenture (For Unsecured Debt Securities), dated as of March 1, 2003, between Texas Competitive Electric Holdings Company LLC (formerly known as TXU Energy Company LLC) and The Bank of New York
4(o)	333-108876 Form S-4 (filed September 17, 2003)	4(b)	—	Officer’s Certificate, dated March 11, 2003, establishing the terms of Texas Competitive Electric Holdings Company LLC’s 6.125% Senior Notes due 2008 and 7.000% Senior Notes due 2013
4(p)	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(q)	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)			—	2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates
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)			—	Summary of Consulting Arrangement, between Donald Evans and Energy Future Holdings Corp.
10(d)			—	Consulting Agreement, dated December 5, 2007, between James R. Huffines and Energy Future Holdings Corp.

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Exhibits	Previously Filed* With File Number	As Exhibit
10(e)			—	Consulting Agreement, dated December 5, 2007, between Lyndon Olson and Energy Future Holdings Corp.
10(f)			—	Energy Future Holdings Corp. Non-employee Director Compensation Arrangements
10(g)	1-12833 Form 8-K (filed February 22, 2006)	10.2	—	EFH Deferred and Incentive Compensation Plan, as amended and restated, dated February 16, 2006
10(h)			—	Amendment to EFH Deferred and Incentive Compensation Plan Trust Agreement, dated October 5, 2007
10(i)	1-12833 Form 10-K (2006) (filed March 2, 2007)	10(u)	—	EFH Executive Annual Incentive Plan, as amended and restated, executed December 29, 2006 to be effective as of January 1, 2006
10(j)			—	EFH Salary Deferral Program, as amended and restated, effective January 1, 2007
10(k)	1-12833 Form 8-K (filed May 23, 2005)	10.7	—	Energy Future Holdings Corp. 2005 Executive Severance Plan
10(l)	1-12833 Form 8-K (filed May 23, 2005)	10.6	—	Energy Future Holdings Corp. Executive Change in Control Policy
10(m)	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(n)			—	Amendment to the EFH Split Dollar Life Insurance Program, effective as of October 10, 2007
10(o)	1-12833 Form 8-K (filed February 22, 2006)	10.5	—	EFH Second Supplemental Retirement Plan, as amended and restated, dated February 16, 2006
10(p)			—	Employment Agreement, dated January 6, 2008, by and between John F. Young and Energy Future Holdings Corp.
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(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(s)			—	Sale Participation Agreement, dated as of February 1, 2008, by and between John F. Young and Texas Energy Future Holdings Limited Partnership
10(t)			—	Severance and Release Agreement, dated October 10, 2007, by and between C. John Wilder and Energy Future Holdings Corp.
10(u)			—	Additional Payment Agreement, dated October 10, 2007, by and among C. John Wilder, Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and Texas Competitive Electric Holdings Company LLC
10(v)	1-12833 Form 10-K (2004) (filed March 16, 2005)	10(l)	—	Employment Agreement, dated May 14, 2004, by and between David Campbell and Energy Future Holdings Corp.

253

Exhibits	Previously Filed* With File Number	As Exhibit
10(w)			—	Amendment to Employment Agreement, dated September 28, 2007, by and between David Campbell and Energy Future Holdings Corp.
10(x)			—	Second Amendment to Employment Agreement, dated October 4, 2007, by and between David Campbell and Energy Future Holdings Corp.
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(z)			—	Summary of Employment Arrangement for Michael Greene
10(aa)			—	Summary of Employment Arrangement by and between Rob Walters and Energy Future Holdings Corp.
10(bb)			—	Severance and Release Agreement, dated March 31, 2008 by and between David P. Poole and Energy Future Holdings Corp.
10(cc)			—	Additional Payment Agreement, dated October 10, 2007, by and among David P. Poole, Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and Texas Competitive Electric Holdings Company LLC
10(dd)			—	Summary of Employment Arrangement for Mike McCall
10(ee)			—	Employment Agreement, dated December 31, 2007, by and among James Burke, Energy Future Holdings Corp. and TXU Energy Retail Company LLC
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)			—	Summary of Consulting Arrangement, between T.L. Baker and Energy Future Holdings Corp.
10(hh)			—	Summary of Employment Arrangement for Charles R. Enze
10(ii)			—	Summary of Employment Arrangement between M. Rizwan Chand and Energy Future Holdings Corp.
10(jj)	1-12833 Form 10-K (2006) (filed March 2, 2007)	10(g)	—	Employment Agreement, dated August 24, 2004, by and between Jonathan A. Siegler and Energy Future Holdings Corp.
10(kk)			—	Amendment to Employment Agreement, dated September 28, 2007, by and between Jonathan A. Siegler and Energy Future Holdings Corp.
10(ll)			—	Second Amendment to Employment Agreement, dated October 4, 2007, by and between Jonathan A. Siegler and Energy Future Holdings Corp.
10(mm)			—	Additional Payment Agreement, dated October 10, 2007, by and among Jonathan A. Siegler, Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and Texas Competitive Electric Holdings Company LLC
10(nn)			—	Deferred Share Agreement, dated October 9, 2007, by and between James Burke and Texas Energy Future Holdings Limited Partnership

254

Exhibits	Previously Filed* With File Number	As Exhibit
10(oo)			—	Deferred Share Agreement, dated October 9, 2007 by and between Charles Enze and Texas Energy Future Holdings Limited Partnership
10(pp)			—	Deferred Share Agreement, dated October 9, 2007, by and between Michael McCall and Texas Energy Future Holdings Limited Partnership
10(qq)			—	Deferred Share Agreement, dated October 9, 2007, by and between Michael Greene and Texas Energy Future Holdings Limited Partnership
	Credit Agreements
10(rr)	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(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(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
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(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

255

Exhibits	Previously Filed* With File Number	As Exhibit
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(xx)			—	$4,500,000,000 Senior Unsecured Interim Loan Agreement, dated as of October 10, 2007, among Energy Future Holdings Corp., as the borrower, the several lenders from time to time parties thereto, Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as syndication agent, Morgan Stanley Senior Funding, Inc., Goldman Sachs Credit Partners L.P., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities Inc. and Lehman Brothers Inc., as joint lead arrangers and bookrunners, and Citibank, N.A.., Credit Suisse Securities (USA) LLC, JPMorgan Chase Bank, N.A. and Lehman Commercial Paper Inc., as co-documentation agents
10(yy)			—	Senior Unsecured Guarantee, dated as of October 10, 2007, by the guarantors party thereto in favor of Morgan Stanley Senior Funding, Inc., as administrative agent for the benefit of the secured parties under the $4,500,000,000 Senior Unsecured Interim Loan Agreement
10(zz)			—	$6,750,000,000 Senior Unsecured Interim Loan Agreement, dated as of October 10, 2007, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC and TCEH Finance, Inc., as the borrower, the several lenders from time to time parties thereto, Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as syndication agent, Morgan Stanley Senior Funding, Inc., Goldman Sachs Credit Partners L.P., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities Inc. and Lehman Brothers Inc., as joint lead arrangers and bookrunners, and Citibank, N.A.., Credit Suisse Securities (USA) LLC, JPMorgan Chase Bank, N.A. and Lehman Commercial Paper Inc., as co-documentation agents
10(aaa)			—	Senior Unsecured Guarantee, dated as of October 10, 2007, by the guarantors party thereto in favor of Morgan Stanley Senior Funding, Inc., as administrative agent for the benefit of the secured parties under the $6,750,000,000 Senior Unsecured Interim Loan Agreement

256

Exhibits	Previously Filed* With File Number	As Exhibit
10(bbb)	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(ccc)	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(ddd)	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
10(eee)			—	Stipulation as approved by the PUC in Docket No. 34077
10(fff)			—	Amendment to Stipulation Regarding Section 1, Paragraph 35 and Exhibit B in Docket No. 34077
10(ggg)	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(hhh)	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(iii)	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(jjj)	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(kkk)	1-12833 Form 10-K (2004) (filed March 16, 2005)	10(xx)	—	Settlement Agreement, dated January 27, 2005, between Energy Future Holdings Corp. and certain other parties thereto regarding the settlement of certain claims related to TXU Europe
10(lll)	1-12833 Form 10-K (2004) (filed March 16, 2005)	10(yy)	—	Memorandum of Understanding, dated January 20, 2005, regarding the settlement of certain shareholder claims made against Energy Future Holdings Corp.
10(mmm)	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)

257

Exhibits	Previously Filed* With File Number	As Exhibit
10(nnn)	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(ooo)	1-12833 Form 10-Q (Quarter ended September 30, 2006) (filed November 9, 2006)	10(a)	—	Form of Purchase Order by and between Generation Development Company LLC (formerly known as TXU Generation Development Company LLC) and The Babcox and Wilcox Company, effective as of June 5, 2006 (confidential treatment has been requested for portions of this exhibit)
10(ppp)	1-12833 Form 10-Q (Quarter ended September 30, 2006) (filed November 9, 2006)	10(c)	—	Form of Purchase Order by and between Generation Development Company LLC and Alstom Power Inc., effective as of September 21, 2006 (confidential treatment has been requested for portions of this exhibit)
10(qqq)	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(rrr)	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(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(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(uuu)			—	Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(vvv)			—	ISDA Master Agreement, dated as of October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International
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(xxx)			—	Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Credit Suisse International
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.

258

Exhibits	Previously Filed* With File Number	As Exhibit
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(aaaa)	333-100240 Form 10-Q (Quarter ended September 30, 2007) (filed November 14, 2007)	3.B		—	Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Company LLC, dated as of October 10, 2007, executed by Oncor Electric Delivery Holdings Company LLC
10(bbbb)				—	Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Holdings Company LLC, dated as of October 10, 2007, executed by Energy Future Intermediate Holding Company LLC
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
(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 David A. Campbell, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 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)				—	Adjusted EBITDA reconciliation for the years ended December 31, 2007 and 2006

* 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.

259

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 31, 2008	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 Officer and Director	March 31, 2008
	(John F. Young, President and Chief Executive Officer)
/s/	DAVID A. CAMPBELL	Principal Financial Officer	March 31, 2008
	(David A. Campbell, Executive Vice President and Chief Financial Officer)
/s/	STANLEY J. SZLAUDERBACH	Principal Accounting Officer	March 31, 2008
	(Stanley J. Szlauderbach, Senior Vice President and Controller)
/s/	DONALD L. EVANS	Director	March 31, 2008
	(Donald L. Evans, Chairman of the Board)
/s/	DAVID BONDERMAN	Director	March 31, 2008
	(David Bonderman)
/s/	FREDERICK M. GOLTZ	Director	March 31, 2008
	(Frederick M. Goltz)
/s/	JAMES R. HUFFINES	Director	March 31, 2008
	(James R. Huffines)
/s/	SCOTT LEBOVITZ	Director	March 31, 2008
	(Scott Lebovitz)
/s/	JEFFREY LIAW	Director	March 31, 2008
	(Jeffrey Liaw)
/s/	MARC S. LIPSCHULTZ	Director	March 31, 2008
	(Marc S. Lipschultz)
/s/	MICHAEL MACDOUGALL	Director	March 31, 2008
	(Michael MacDougall)
/s/	LYNDON L. OLSON, JR.	Director	March 31, 2008
	(Lyndon L. Olson, Jr.)
/s/	KENNETH PONTARELLI	Director	March 31, 2008
	(Kenneth Pontarelli)

260

	Signature	Title	Date
/s/	WILLLIAM K. REILLY	Director	March 31, 2008
	(William K. Reilly)
/s/	JONATHAN D. SMIDT	Director	March 31, 2008
	(Jonathan D. Smidt)
/s/	WILLIAM J. YOUNG	Director	March 31, 2008
	(William J. Young)
/s/	KNEELAND YOUNGBLOOD	Director	March 31, 2008
	(Kneeland Youngblood)

261

EFH Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2007

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 8-K (filed October 11, 2007)	3.2	—	Amended and Restated Bylaws of Energy Future Holdings Corp., dated October 10, 2007
(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(ff)	—	Indenture, dated as of January 1, 1998, relating to Energy Future Holdings Corp.’s 6.375% Series C Exchange Notes
4(b)	1-12833 Form 10-K (1997) (filed March 27, 1998)	4(hh)	—	Officer’s Certificate establishing the terms of Energy Future Holdings Corp.’s Series C Exchange Notes
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. 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(d)	1-12833 Form 10-K (2005) (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
4(e)	1-12833 Form 10-K (2005) (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(f)	1-12833 Form 10-K (2005) (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

Exhibits	Previously Filed* With File Number	As Exhibit
4(g)	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(h)	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, as Trustee
4(i)	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
4(j)	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(k)	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(l)	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, as Trustee
4(m)	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% Debentures due 2022
	Texas Competitive Electric Holdings Company LLC
4(n)	333-108876 Form S-4 (filed September 17, 2003)	4(a)	—	Indenture (For Unsecured Debt Securities), dated as of March 1, 2003, between Texas Competitive Electric Holdings Company LLC (formerly known as TXU Energy Company LLC) and The Bank of New York
4(o)	333-108876 Form S-4 (filed September 17, 2003)	4(b)	—	Officer’s Certificate, dated March 11, 2003, establishing the terms of Texas Competitive Electric Holdings Company LLC’s 6.125% Senior Notes due 2008 and 7.000% Senior Notes due 2013
4(p)	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(q)	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)			—	2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates
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)			—	Summary of Consulting Arrangement, between Donald Evans and Energy Future Holdings Corp.
10(d)			—	Consulting Agreement, dated December 5, 2007, between James R. Huffines and Energy Future Holdings Corp.

Exhibits	Previously Filed* With File Number	As Exhibit
10(e)			—	Consulting Agreement, dated December 5, 2007, between Lyndon Olson and Energy Future Holdings Corp.
10(f)			—	Energy Future Holdings Corp. Non-employee Director Compensation Arrangements
10(g)	1-12833 Form 8-K (filed February 22, 2006)	10.2	—	EFH Deferred and Incentive Compensation Plan, as amended and restated, dated February 16, 2006
10(h)			—	Amendment to EFH Deferred and Incentive Compensation Plan Trust Agreement, dated October 5, 2007
10(i)	1-12833 Form 10-K (2006) (filed March 2, 2007)	10(u)	—	EFH Executive Annual Incentive Plan, as amended and restated, executed December 29, 2006 to be effective as of January 1, 2006
10(j)			—	EFH Salary Deferral Program, as amended and restated, effective January 1, 2007
10(k)	1-12833 Form 8-K (filed May 23, 2005)	10.7	—	Energy Future Holdings Corp. 2005 Executive Severance Plan
10(l)	1-12833 Form 8-K (filed May 23, 2005)	10.6	—	Energy Future Holdings Corp. Executive Change in Control Policy
10(m)	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(n)			—	Amendment to the EFH Split Dollar Life Insurance Program, effective as of October 10, 2007
10(o)	1-12833 Form 8-K (filed February 22, 2006)	10.5	—	EFH Second Supplemental Retirement Plan, as amended and restated, dated February 16, 2006
10(p)			—	Employment Agreement, dated January 6, 2008, by and between John F. Young and Energy Future Holdings Corp.
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(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(s)			—	Sale Participation Agreement, dated as of February 1, 2008, by and between John F. Young and Texas Energy Future Holdings Limited Partnership
10(t)			—	Severance and Release Agreement, dated October 10, 2007, by and between C. John Wilder and Energy Future Holdings Corp.
10(u)			—	Additional Payment Agreement, dated October 10, 2007, by and among C. John Wilder, Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and Texas Competitive Electric Holdings Company LLC
10(v)	1-12833 Form 10-K (2004) (filed March 16, 2005)	10(l)	—	Employment Agreement, dated May 14, 2004, by and between David Campbell and Energy Future Holdings Corp.

Exhibits	Previously Filed* With File Number	As Exhibit
10(w)			—	Amendment to Employment Agreement, dated September 28, 2007, by and between David Campbell and Energy Future Holdings Corp.
10(x)			—	Second Amendment to Employment Agreement, dated October 4, 2007, by and between David Campbell and Energy Future Holdings Corp.
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(z)			—	Summary of Employment Arrangement for Michael Greene
10(aa)			—	Summary of Employment Arrangement by and between Rob Walters and Energy Future Holdings Corp.
10(bb)			—	Severance and Release Agreement, dated March 31, 2008 by and between David P. Poole and Energy Future Holdings Corp.
10(cc)			—	Additional Payment Agreement, dated October 10, 2007, by and among David P. Poole, Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and Texas Competitive Electric Holdings Company LLC
10(dd)			—	Summary of Employment Arrangement for Mike McCall
10(ee)			—	Employment Agreement, dated December 31, 2007, by and among James Burke, Energy Future Holdings Corp. and TXU Energy Retail Company LLC
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)			—	Summary of Consulting Arrangement, between T.L. Baker and Energy Future Holdings Corp.
10(hh)			—	Summary of Employment Arrangement for Charles R. Enze
10(ii)			—	Summary of Employment Arrangement between M. Rizwan Chand and Energy Future Holdings Corp.
10(jj)	1-12833 Form 10-K (2006) (filed March 2, 2007)	10(g)	—	Employment Agreement, dated August 24, 2004, by and between Jonathan A. Siegler and Energy Future Holdings Corp.
10(kk)			—	Amendment to Employment Agreement, dated September 28, 2007, by and between Jonathan A. Siegler and Energy Future Holdings Corp.
10(ll)			—	Second Amendment to Employment Agreement, dated October 4, 2007, by and between Jonathan A. Siegler and Energy Future Holdings Corp.
10(mm)			—	Additional Payment Agreement, dated October 10, 2007, by and among Jonathan A. Siegler, Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and Texas Competitive Electric Holdings Company LLC
10(nn)			—	Deferred Share Agreement, dated October 9, 2007, by and between James Burke and Texas Energy Future Holdings Limited Partnership

Exhibits	Previously Filed* With File Number	As Exhibit
10(oo)			—	Deferred Share Agreement, dated October 9, 2007 by and between Charles Enze and Texas Energy Future Holdings Limited Partnership
10(pp)			—	Deferred Share Agreement, dated October 9, 2007, by and between Michael McCall and Texas Energy Future Holdings Limited Partnership
10(qq)			—	Deferred Share Agreement, dated October 9, 2007, by and between Michael Greene and Texas Energy Future Holdings Limited Partnership
	Credit Agreements
10(rr)	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(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(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
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(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

Exhibits	Previously Filed* With File Number	As Exhibit
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(xx)			—	$4,500,000,000 Senior Unsecured Interim Loan Agreement, dated as of October 10, 2007, among Energy Future Holdings Corp., as the borrower, the several lenders from time to time parties thereto, Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as syndication agent, Morgan Stanley Senior Funding, Inc., Goldman Sachs Credit Partners L.P., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities Inc. and Lehman Brothers Inc., as joint lead arrangers and bookrunners, and Citibank, N.A.., Credit Suisse Securities (USA) LLC, JPMorgan Chase Bank, N.A. and Lehman Commercial Paper Inc., as co-documentation agents
10(yy)			—	Senior Unsecured Guarantee, dated as of October 10, 2007, by the guarantors party thereto in favor of Morgan Stanley Senior Funding, Inc., as administrative agent for the benefit of the secured parties under the $4,500,000,000 Senior Unsecured Interim Loan Agreement
10(zz)			—	$6,750,000,000 Senior Unsecured Interim Loan Agreement, dated as of October 10, 2007, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC and TCEH Finance, Inc., as the borrower, the several lenders from time to time parties thereto, Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as syndication agent, Morgan Stanley Senior Funding, Inc., Goldman Sachs Credit Partners L.P., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities Inc. and Lehman Brothers Inc., as joint lead arrangers and bookrunners, and Citibank, N.A.., Credit Suisse Securities (USA) LLC, JPMorgan Chase Bank, N.A. and Lehman Commercial Paper Inc., as co-documentation agents
10(aaa)			—	Senior Unsecured Guarantee, dated as of October 10, 2007, by the guarantors party thereto in favor of Morgan Stanley Senior Funding, Inc., as administrative agent for the benefit of the secured parties under the $6,750,000,000 Senior Unsecured Interim Loan Agreement

Exhibits	Previously Filed* With File Number	As Exhibit
10(bbb)	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(ccc)	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(ddd)	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
10(eee)			—	Stipulation as approved by the PUC in Docket No. 34077
10(fff)			—	Amendment to Stipulation Regarding Section 1, Paragraph 35 and Exhibit B in Docket No. 34077
10(ggg)	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(hhh)	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(iii)	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(jjj)	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(kkk)	1-12833 Form 10-K (2004) (filed March 16, 2005)	10(xx)	—	Settlement Agreement, dated January 27, 2005, between Energy Future Holdings Corp. and certain other parties thereto regarding the settlement of certain claims related to TXU Europe
10(lll)	1-12833 Form 10-K (2004) (filed March 16, 2005)	10(yy)	—	Memorandum of Understanding, dated January 20, 2005, regarding the settlement of certain shareholder claims made against Energy Future Holdings Corp.
10(mmm)	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)

Exhibits	Previously Filed* With File Number	As Exhibit
10(nnn)	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(ooo)	1-12833 Form 10-Q (Quarter ended September 30, 2006) (filed November 9, 2006)	10(a)	—	Form of Purchase Order by and between Generation Development Company LLC (formerly known as TXU Generation Development Company LLC) and The Babcox and Wilcox Company, effective as of June 5, 2006 (confidential treatment has been requested for portions of this exhibit)
10(ppp)	1-12833 Form 10-Q (Quarter ended September 30, 2006) (filed November 9, 2006)	10(c)	—	Form of Purchase Order by and between Generation Development Company LLC and Alstom Power Inc., effective as of September 21, 2006 (confidential treatment has been requested for portions of this exhibit)
10(qqq)	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(rrr)	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(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(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(uuu)			—	Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(vvv)			—	ISDA Master Agreement, dated as of October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International
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(xxx)			—	Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Credit Suisse International
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.

Exhibits	Previously Filed* With File Number	As Exhibit
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(aaaa)	333-100240 Form 10-Q (Quarter ended September 30, 2007) (filed November 14, 2007)	3.B	—	Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Company LLC, dated as of October 10, 2007, executed by Oncor Electric Delivery Holdings Company LLC
10(bbbb)			—	Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Holdings Company LLC, dated as of October 10, 2007, executed by Energy Future Intermediate Holding Company LLC
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
(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 David A. Campbell, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 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)			—	Adjusted EBITDA reconciliation for the years ended December 31, 2007 and 2006

* 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.