As filed with the Securities and Exchange Commission on December 23, 2008

Registration No. 333-153529

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 2 to

FORM S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Energy Future Holdings Corp.

(Exact name of registrant issuer as specified in its charter)

SEE TABLE OF ADDITIONAL REGISTRANTS

Texas	4911	75-2669310
(State or other jurisdiction of incorporation)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1601 Bryan Street

Dallas, Texas 75201-3411

(214) 812-4600

(Address, including zip code, and telephone number, including area code, of registrants’ principal executive offices)

Andrew M. Wright

EFH Corporate Services Company

Vice President and Associate General Counsel

1601 Bryan Street

Dallas, Texas 75201-3411

(214) 812-4600

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Approximate date of commencement of proposed exchange offers:  As soon as practicable after this Registration Statement is declared effective.

If the securities being registered on this form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, please check the following box.  ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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

Large accelerated filer   ¨	Accelerated filer   ¨
Non-accelerated filer  x    (Do not check if a small reporting company)	Small reporting company   ¨

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Amount to be Registered	Proposed Maximum Offering Price Per Note	Proposed Maximum Aggregate Offering Price (1)	Amount of Registration Fee (2)
10.875% Senior Notes due 2017	$2,000,000,000	100%	$2,000,000,000	$78,600
11.250%/12.000% Senior Toggle Notes due 2017(3)	$2,650,000,000	100%	$2,650,000,000	$104,145
Guarantees of 10.875% Senior Notes due 2017(4)	N/A	N/A	N/A	N/A(5)
Guarantees of 11.250%/12.000% Senior Toggle Notes due 2017(4)	N/A	N/A	N/A	N/A(5)

(1) Estimated solely for the purpose of calculating the registration fee under Rule 457(f) of the Securities Act of 1933, as amended (the “Securities Act”).

(2) Pursuant to Rule 457(p), a portion of the registration fee described in the table above in the aggregate amount of $176,850 is being paid through the use of a credit of Energy Future Holdings Corp. (formerly known as TXU Corp.) from the fees paid in connection with its Registration Statement on Form S-3 (SEC File No. 333-115159), initially filed by TXU Corp. (now known as Energy Future Holdings Corp.) on May 4, 2004.

(3) Includes $150,000,000 principal amount of such notes that will be issued by EFH Corp. on May 1, 2009, in lieu of cash interest payments thereon. Such additional principal amount constitutes EFH Corp.’s reasonable good faith estimate of the amount of such notes that will be paid as interest in lieu of cash.

(4) See inside facing page for table of registrant guarantors.

(5) Pursuant to Rule 457(n) under the Securities Act, no separate filing fee is required for the guarantees.

The Registrants hereby amend this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrants shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

Table of Additional Registrant Guarantors

Exact Name of Registrant Guarantor as Specified in its Charter (or Other Organizational Document)	State or Other Jurisdiction of Incorporation or Organization	I.R.S. Employer Identification Number	Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant Guarantor’s Principal Executive Offices
Energy Future Competitive Holdings Company	Texas	75-1837355	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Energy Future Intermediate Holding Company LLC	Delaware	26-1191638	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED DECEMBER 23, 2008

PRELIMINARY PROSPECTUS

ENERGY FUTURE HOLDINGS CORP.

Offers to Exchange

$2,000,000,000 aggregate principal amount of its 10.875% Senior Notes due 2017 and $2,500,000,000 aggregate principal amount of its 11.250%/12.000% Senior Toggle Notes due 2017 (collectively, the “exchange notes”), each of which have been registered under the Securities Act of 1933, as amended (the “Securities Act”), for any and all of its outstanding 10.875% Senior Notes due 2017 and 11.250%/12.000% Senior Toggle Notes due 2017 (collectively, the “outstanding notes”), respectively (such transactions, collectively, the “exchange offers”).

We are conducting the exchange offers in order to provide you with an opportunity to exchange your unregistered outstanding notes for freely tradable notes that have been registered under the Securities Act.

The Exchange Offers

• We will exchange all outstanding notes that are validly tendered and not validly withdrawn for an equal principal amount of exchange notes that are freely tradable.

• You may withdraw tenders of outstanding notes at any time prior to the expiration date of the exchange offers.

• The exchange offers expire at 11:59 p.m., New York City time, on                     , 2009, unless extended. We do not currently intend to extend the expiration date.

• The exchange of outstanding notes for exchange notes in the exchange offers will not be a taxable event for U.S. federal income tax purposes.

• The terms of the exchange notes to be issued in the exchange offers are substantially identical to the outstanding notes of the respective series, except that the exchange notes will be freely tradable.

Results of the Exchange Offers

• Except as prohibited by applicable law, the exchange notes may be sold in the over-the-counter market, in negotiated transactions or through a combination of such methods. We do not plan to list the exchange notes on a national market.

All untendered outstanding notes will continue to be subject to the restrictions on transfer set forth in the outstanding notes and in the indenture. In general, the outstanding notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the exchange offers, we do not currently anticipate that we will register the outstanding notes under the Securities Act.

Each broker-dealer that receives exchange notes for its own account in the exchange offers must acknowledge that it will deliver a prospectus in connection with any resale of those exchange notes. The letter of transmittal states that by so acknowledging and delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for outstanding notes where the broker-dealer acquired such outstanding notes as a result of market-making or other trading activities.

We have agreed that, for a period of 90 days after the consummation of the exchange offers (or until the broker-dealer no longer holds registrable securities), we will make this prospectus available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution.”

See “Risk Factors” beginning on page 24 for a discussion of certain risks that you should consider before participating in the exchange offers.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of the exchange notes to be distributed in the exchange offers or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is                     , 2008.

You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with different information. The prospectus may be used only for the purposes for which it has been published, and no person has been authorized to give any information not contained herein. If you receive any other information, you should not rely on it. We are not making an offer of these securities in any state where the offer is prohibited.

TABLE OF CONTENTS

	Page
Prospectus Summary	1
Risk Factors	24
Forward-Looking Statements	45
The Transactions	47
Use of Proceeds	50
Capitalization	50
Energy Future Holdings Corp. and Subsidiaries Unaudited Pro Forma Condensed Statement of Consolidated Income (Loss)	51
Energy Future Holdings Corp. Selected Historical Consolidated Financial Data	56
Management’s Discussion and Analysis of Financial Condition and Results of Operations	62
Our Businesses	147
Regulation and Rates	166
Management	170
Executive Compensation	178
Director Compensation	217
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder matters	220
Certain Relationships and Related Party Transactions	224
The Exchange Offers	228
Description of the Notes	238
Certain U.S. Federal Income Tax Consequences	304
Certain ERISA Considerations	311
Plan of Distribution	313
Legal Matters	314
Experts	314
Available Information	314
Glossary	316
Index to Consolidated Financial Statements	F-1

PROSPECTUS SUMMARY

This summary highlights selected information appearing elsewhere in this prospectus. This summary does not contain all of the information that you should consider before participating in the exchange offers. You should carefully read the entire prospectus, including information set forth in the sections entitled “Risk Factors,” “Energy Future Holdings Corp. and Subsidiaries Unaudited Pro Forma Condensed Statement of Consolidated Income (Loss),” “Energy Future Holdings Corp. Selected Historical Consolidated Financial Data,” and the other financial data and related notes included elsewhere in this prospectus.

On October 10, 2007, Texas Energy Future Merger Sub Corp (“Merger Sub”) merged with and into EFH Corp. (the “Merger”). As a result of the Merger, investment funds associated with or designated by Kohlberg Kravis Roberts & Co. (“KKR”), TPG Capital, L.P. (“TPG”) and Goldman, Sachs & Co. (“Goldman Sachs”, and together with KKR and TPG, the “Sponsor Group”), and certain other co-investors, including affiliates of Citigroup Global Markets Inc., Morgan Stanley & Co. Incorporated and LB I Group (collectively, the “Investors”), own EFH Corp. through Texas Energy Future Holdings Limited Partnership (“Texas Holdings”), with the Sponsor Group controlling Texas Holdings’ general partner, Texas Energy Future Capital Holdings LLC (the “General Partner”).

The financial information presented in this prospectus is presented for two periods: Predecessor and Successor, which primarily relate to the periods preceding the Merger and the periods succeeding the Merger, respectively. Financial information identified in this prospectus as “pro forma” gives effect to the consummation of the Merger and the related financing transactions described in this prospectus.

Unless the context otherwise requires or as otherwise indicated, references in this prospectus to “we,” “our” and “us” refer to Energy Future Holdings Corp. and its consolidated subsidiaries. References to “EFH Corp.” refer to Energy Future Holdings Corp. and not to any of its subsidiaries. See “Glossary” for other defined terms.

Our Businesses and Strategy

We are a Dallas-based energy company that manages a portfolio of competitive and regulated energy businesses in Texas. We are a holding company conducting our operations principally through our subsidiaries, Texas Competitive Electric Holdings Company LLC (“TCEH”) and Oncor Electric Delivery Company LLC (“Oncor”).

TCEH is a holding company for businesses 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.

As of September 30, 2008, Luminant owned or leased 18,365 megawatts (“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 U.S. Luminant is currently constructing three lignite/coal-fueled generation units in Texas with expected generation capacity totaling approximately 2,200 MW. Permits have been obtained for construction of the three units, which are expected to come on-line in 2009 and 2010. TXU Energy provides competitive electricity and related services to approximately 2.2 million retail electricity customers in Texas. As of September 30, 2008, TXU Energy’s estimated share of the total Electricity Reliability Council of Texas (“ERCOT”) retail market for residential and business market electricity customers was approximately 37% and 26%, respectively (based on customer counts).

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Oncor is engaged in regulated electricity transmission and distribution operations in Texas that are primarily regulated by the Public Utility Commission of Texas (the “PUCT”). Oncor provides both distribution services to retail electric providers that sell electricity to consumers and transmission services to other electricity distribution companies, cooperatives and municipalities. It 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. A significant portion of Oncor’s revenues represent fees for delivery services provided to TCEH. Distribution revenues from TCEH represented 40% of Oncor’s total revenues for the nine months ended September 30, 2008 and 41% of Oncor’s total revenues for the year ended December 31, 2007.

Upon the consummation of the Merger, EFH Corp. and Oncor implemented certain structural and operational “ring-fencing” measures based on commitments made by Texas Holdings and Oncor to the PUCT that further separated 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 “The Transactions—Ring-Fencing” for a description of the material terms of the ring-fencing measures.

At September 30, 2008, we had approximately 8,000 full-time employees, including approximately 2,600 employees under collective bargaining agreements.

Our Market

We operate 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 generators, power marketers, transmission service providers, distribution service providers, REPs and consumers.

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 U.S. over the same period. For 2007, hourly demand peaked at 62,188 MW. The ERCOT market has limited interconnections to other markets in the U.S., 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 U.S. Federal Energy Regulatory Commission (“FERC”).

Since 1996, over 34,000 MW of mostly natural gas-fueled and wind generation capacity has been developed in the ERCOT market. Net generation capacity in the ERCOT market for 2008 totals approximately 72,820 MW, excluding mothballed capacity; approximately 65% of this capacity is natural gas-fueled generation and approximately 27% of this capacity consists of lignite/coal and nuclear-fueled baseload generation. ERCOT currently has a target reserve margin level of approximately 12.5%; the reserve margin is projected by ERCOT to be 15.8% in 2009, 21.2% in 2010, and drop to 15.8% by 2014.

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 2007. 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

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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 in ERCOT 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 zone, with the Sandow unit in the South zone.

The ERCOT market operates under reliability standards set by the North American Electric Reliability Corporation (“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 distribution service area. Oncor participates with the ERCOT independent system operator and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to meet reliability needs, increase bulk power transfer capability to remove existing constraints and interconnect generation on the ERCOT transmission grid.

Our Strategies

Each of our 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 our strategy include:

• Increase value from existing businesses. Our strategy focuses on striving for top quartile or better performance across our operations in terms of reliability, cost and customer service. We will continue to focus on upgrading four critical skill sets: operational excellence across each business; market leadership and customer focus; a systematic risk/return mindset applied to all key decisions; and rigorous performance management targeting industry-leading performance standards for productivity,

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reliability and customer service. An example of how we implement these principles is a program called the “Luminant Operating System,” which is a program to drive ongoing productivity improvements in Luminant’s operations through application of lean operating techniques and deployment of a high-performance industrial culture.

• Pursue growth opportunities across business lines. We will selectively target growth opportunities in each of our business lines. Our scale in each of our operating businesses allows us 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. We 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 our performance over the near term but can enhance our growth profile over time. Specific growth initiatives for each business include:

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

• TXU Energy: Increase the number of customers served throughout the competitive ERCOT market areas by delivering superior value to customers through high quality customer service and innovative energy products, including pioneering energy efficiency initiatives and service offerings.

• Oncor: Invest in technology upgrades including advanced metering systems and construct new transmission and distribution facilities to meet the needs of the growing Texas market.

The growth initiatives at Oncor benefit from regulatory capital recovery mechanisms known as “capital trackers” that Oncor believes enable adequate and timely recovery of transmission investments and advanced metering investments through the rates charged by Oncor.

• Reduce the volatility of cash flows through a commodity risk management strategy. A key component of our risk management strategy is our 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 our exposure to natural gas prices. As of October 24, 2008, approximately 2.1 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 280,000 GWh at an assumed 7.5 MMBtu/MWh market heat rate) have been effectively sold forward over the period from 2008 to 2014, at average annual prices ranging from $7.20 per MMBtu to $8.35 per MMBtu. Taking into consideration the estimated portfolio impacts of our retail electricity business, these natural gas hedging transactions result in us having effectively hedged approximately 77% of our expected baseload generation natural gas price exposure (on an average basis for 2008 through 2014). 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 September 30, 2008, more than 95% of the hedging transactions were secured or supported by first-lien interests in TCEH’s assets and result in no direct liquidity exposure.

• Pursue new environmental initiatives. We are committed to continue to operate in compliance with all environmental laws, rules and regulations and to reduce our impact on the environment. We have formed a Sustainable Energy Advisory Board that advises us in our pursuit of technology development

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opportunities that reduce our impact on the environment while balancing the need to address the energy requirements of Texas. Our Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, customers, economic development in Texas and technology/reliability standards. In addition, we are focused on and are pursuing opportunities to reduce emissions from our existing and planned new lignite/coal-fueled generation units in the ERCOT market. Luminant has voluntarily committed to reduce emissions of mercury, nitrogen oxide (“NO_x”) and sulfur dioxide (“SO₂”) at its existing units, so that the total of those emissions from both existing and new lignite/coal-fueled units is 20% below 2005 levels. We expect Luminant to make these reductions through a combination of investment in new emission control equipment, new coal cleaning technologies and optimizing fuel blends. We also expect such investments to provide economic benefits by reducing future costs associated with complying with environmental emissions standards. In addition, we expect to invest $400 million over a five year period beginning in 2008 in programs designed to encourage customer electricity demand efficiencies.

Recent Developments

Oncor Minority Interest Sale

On November 5, 2008, Oncor issued and sold 19.75% of its outstanding equity interests to Texas Transmission Investment LLC, an entity indirectly owned by a private investment group led by OMERS Administration Corporation, acting through its infrastructure investment entity Borealis Infrastructure Management Inc., and the Government of Singapore Investment Corporation, acting through its private equity and infrastructure arm GIC Special Investments Pte Ltd. Additionally, Hunt Strategic Utility Investment, LLC has a 0.1975% indirect investment in Oncor through such private investment group.

The consideration paid by Texas Transmission Investment LLC for the equity interests issued and sold in the issuance was $1.254 billion. At the closing of the issuance to Texas Transmission Investment LLC, Oncor also offered and sold approximately 0.21% of its outstanding equity interests to certain members of Oncor’s management team. Accordingly, EFH Corp. now indirectly owns approximately 80.04% of Oncor, Oncor management owns approximately 0.21% of Oncor and Texas Transmission Investment LLC owns 19.75% of Oncor.

The proceeds (net of closing costs) of $1.253 billion received by Oncor from Texas Transmission Investment LLC and the members of Oncor management were distributed ultimately to EFH Corp. Under the terms of certain financing arrangements of EFH Corp. and TCEH, under certain circumstances, EFH Corp. is required to repay certain outstanding intercompany loans from TCEH. As of November 5, 2008, approximately $837 million of such intercompany loans were outstanding. On November 6, 2008, EFH Corp. repaid the $253 million balance of such loans that related to payments of principal and interest on EFH Corp. debt.

In connection with the closings of the issuances to Texas Transmission Investment LLC and to members of Oncor management, the sole member of Oncor Holdings entered into a Second Amended and Restated Limited Liability Company Agreement of Oncor Holdings and the members of Oncor entered into a Second Amended and Restated Limited Liability Company Agreement of Oncor. In addition, Oncor and certain other parties, including Texas Transmission Investment LLC, entered into an Investor Rights Agreement, a Registration Rights Agreement and an Amended and Restated Tax Sharing Agreement.

The Second Amended and Restated Limited Liability Company Agreement of Oncor Holdings, among other things, sets out the member’s governance rights in respect of its ownership interests in Oncor Holdings. Among other things, the Second Amended and Restated Limited Liability Company Agreement of Oncor Holdings provides for the management of Oncor Holdings by a board of directors consisting of nine members, including at least six independent directors, two directors designated indirectly by EFH Corp. and one director that is also an officer of Oncor Holdings.

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The Second Amended and Restated Limited Liability Company Agreement of Oncor Holdings also prohibits Oncor Holdings and its subsidiaries from taking certain material actions without prior special approvals by the member and/or some or all of the independent directors. It also requires that any changes to Oncor Holdings’ procedures and limitations on declaring and paying distributions be approved by (i) a majority of the independent directors and (ii) all of the EFH Corp. directors.

The Second Amended and Restated Limited Liability Company Agreement of Oncor, among other things, sets out the members’ respective governance rights in respect of their ownership interests in Oncor. Among other things, the Second Amended and Restated Limited Liability Company Agreement of Oncor provides for the management of Oncor by a board of directors consisting of 11 members, including at least six Independent Directors (as defined in the Second Amended and Restated Limited Liability Company Agreement of Oncor), two directors designated directly or indirectly by Texas Transmission Investment LLC (subject to certain conditions), two directors designated indirectly by EFH Corp. and one director that is also an officer of Oncor. The nine current members of Oncor’s board of directors retained their positions, and Richard C. Byers and Steven J. Zucchet have been selected to serve on Oncor’s board of directors as the two directors designated by Texas Transmission Investment LLC.

The Second Amended and Restated Limited Liability Company Agreement of Oncor prohibits Oncor and its subsidiaries from taking certain material actions outside the ordinary course of business without prior approvals by the members, some or all of the Independent Directors and/or the directors designated by one or more of the members.

The Second Amended and Restated Limited Liability Company Agreement of Oncor also requires that any changes to Oncor’s procedures and limitations on declaring and paying distributions be approved by (i) a majority of the Independent Directors, (ii) all of the EFH Corp. directors and (iii) the Texas Transmission Investment LLC director(s) present and voting, provided that at least one Texas Transmission Investment LLC director must be present and voting in order to approve such matter. In addition, any annual budget with an aggregate amount of capital and operating and maintenance expenditures that are more than 10% less than the capital and operating and maintenance expenditures in the annual budget for the immediately prior fiscal year must be approved by (a) a majority of the Independent Directors and (b) the Texas Transmission Investment LLC director(s) present and voting, provided that at least one Texas Transmission Investment LLC director must be present and voting in order to approve such action. Also, any acquisition of or investment in any third-party which involves the purchase of or investment in assets located outside the State of Texas for consideration in an amount greater than $1.5 billion must be approved by (a) a majority of the Independent Directors and (b) the Texas Transmission Investment LLC director(s) present and voting, provided that at least one Texas Transmission Investment LLC director must be present and voting in order to approve such action.

Additionally, the Second Amended and Restated Limited Liability Company Agreement of Oncor contains provisions regulating capital accounts of members, allocations of profits and losses and tax allocation and withholding.

The Investor Rights Agreement governs certain rights of certain members of Oncor and EFH Corp. arising out of their direct or indirect ownership of Oncor membership interests, including, without limitation, transfers of Oncor membership interests and restrictions thereon. Among other transfer restrictions, the Investor Rights Agreement provides that, prior to the earlier of the completion of a qualified initial public offering or seven years from the date of the Investor Rights Agreement, Texas Transmission Investment LLC may transfer its Oncor membership interests only to certain permitted transferees or with the prior approval of Oncor Holdings. Following such time period, Texas Transmission Investment LLC may transfer its Oncor membership interests under a registration statement or pursuant to applicable securities laws. The Investor Rights Agreement also grants Texas Transmission Investment LLC certain “tag-along” rights in relation to certain sales of Oncor membership interests by Oncor Holdings. Subject to certain conditions, these “tag-along” rights allow Texas

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Transmission Investment LLC to sell a pro-rata portion of its Oncor membership interests in the event of a sale of Oncor membership interests by Oncor Holdings on the same terms as Oncor Holdings would receive for its Oncor membership interests. The agreement further provides that under certain offerings of equity securities occurring before an initial public offering of Oncor, Texas Transmission Investment LLC and Oncor Holdings will receive preemptive rights to purchase their pro-rata share of the equity securities to be sold pursuant to such offerings. The Investor Rights Agreement also provides EFH Corp. with a right of first refusal to purchase any Oncor membership interests to be sold in a permitted sale by Texas Transmission Investment LLC or its permitted transferees.

Additionally, Texas Holdings, EFH Corp., certain of EFH Corp.’s subsidiaries and Oncor Holdings have certain “drag-along” rights in relation to offers from third-parties to purchase their directly or indirectly owned membership interests in Oncor, where the resulting sale would constitute a change of control of Oncor. These “drag-along” rights compel Texas Transmission Investment LLC and all other members of Oncor to sell or otherwise transfer their membership interests in Oncor on substantially the same terms as Texas Holdings, EFH Corp., the EFH Corp. subsidiary or Oncor Holdings (as applicable). Pursuant to the Investor Rights Agreement, all members of Oncor that have entered into such agreement must cooperate with Oncor in connection with an initial public offering of Oncor.

The Registration Rights Agreement grants customary registration rights to certain members of Oncor. Subject to certain limitations set forth in the Registration Rights Agreement, these rights include, without limitation, the following: (i) the right of Oncor Holdings at any time, and after ten years from the date of the Registration Rights Agreement, the right of Texas Transmission Investment LLC, to demand Oncor register a specified amount of membership interests in accordance with the Securities Act of 1933, as amended; (ii) the right of both Oncor Holdings and Texas Transmission Investment LLC to demand registration of a specified amount of membership interests following an initial public offering; and (iii) the right of all members that are parties to the agreement to have their membership interests registered in an Oncor securities offering (with certain exceptions) if Oncor proposes to file a registration statement relating to its membership interests.

Subject to certain exceptions, whenever Oncor is required to effect the registration of any membership interests pursuant to the Registration Rights Agreement, Oncor has agreed to use its best efforts to cause the applicable registration statement to become effective, and to keep each such registration statement effective until the earlier of (a) at least 180 days (or two years for a shelf registration statement) or (b) the time at which all securities registered under such registration statement have been sold.

The Amended and Restated Tax Sharing Agreement provides a contractual framework for cash taxes paid by each of Oncor Holdings and Oncor to EFH Corp., as the indirect parent company of Oncor Holdings and Oncor, and by Oncor to Oncor’s other members, including Texas Transmission Investment LLC.

The foregoing descriptions of the Second Amended and Restated Limited Liability Company Agreement of Oncor Holdings, Second Amended and Restated Limited Liability Company Agreement of Oncor, the Investor Rights Agreement, the Registration Rights Agreement and the Amended and Restated Tax Sharing Agreement are not complete and are qualified in their entirety by reference to the copies thereof filed by EFH Corp. as exhibits to the registration statement on From S-4 filed under the Securities Act with the Securities and Exchange Commission (the “SEC”) on December 23, 2008 with respect to the exchange notes, of which this prospectus is a part.

Notice of Termination of Joint Venture Outsourcing Arrangements

On December 19, 2008, EFH Corp. and TCEH executed a Separation Agreement with Capgemini Energy LP (“Capgemini”), Capgemini America, Inc. and Capgemini North America, Inc. (collectively, “CgE”).

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Simultaneously with the execution of that Separation Agreement, Oncor entered into a substantially similar Separation Agreement with CgE. The Separation Agreements principally provide for (i) notice of termination of each of the Master Framework Agreements, dated as of May 17, 2004, as each has been amended, between Capgemini and each of TCEH and Oncor and the related service agreements under each of the Master Framework Agreements and (ii) termination of the joint venture arrangements between EFH Corp. (and its applicable subsidiaries) and CgE.

The initial Master Framework Agreements were filed as exhibits 10(l) and 10(m) to EFH Corp.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004. Under the Master Framework Agreements and related services agreements, Capgemini provides to EFH Corp. and its subsidiaries outsourced support services, including information technology, customer care and billing, human resources, procurement and certain finance and accounting activities.

Each Separation Agreement acts as a notice of termination under the applicable Master Framework Agreement and the related services agreements. As a result of the “change of control” of EFH Corp. that occurred as a result of the Merger, each of TCEH and Oncor had the right to terminate, without penalty, its Master Framework Agreement. Each of TCEH and Oncor have elected to exercise such right. Consistent with the Master Framework Agreements, to provide for an orderly transition of the services, the Separation Agreements require that Capgemini provide termination assistance services until the services are transitioned back to EFH Corp. and/or to another service provider. The Separation Agreements provide that the services be transitioned by December 31, 2010 (June 30, 2011, in the case of the information technology services). Each Master Framework Agreement will actually terminate when these termination assistance services are completed. EFH Corp. (or its applicable subsidiary) previously provided a termination notice to Capgemini in respect of human resources services and customer care and revenue management services for TXU Energy.

The Separation Agreements provide for the termination of the joint venture arrangement between EFH Corp. (and its applicable subsidiaries) and CgE. As a result, on December 19, 2008:

• the 2.9% limited partnership interest in Capgemini owned by a subsidiary of EFH Corp. was redeemed in exchange for the termination of the license that was granted by a subsidiary of EFH Corp. to Capgemini at the time the Master Framework Agreements were executed in order for Capgemini to use certain information technology assets, primarily consisting of capitalized software to provide services to EFH Corp. and third parties;

• EFH Corp. received approximately $70 million in exchange for the termination of a purchase option agreement pursuant to which subsidiaries of EFH Corp. had the right to “put” to Capgemini (and Capgemini had the right to “call” from a subsidiary of EFH Corp.) EFH Corp.’s 2.9% limited partnership interest in Capgemini and the licensed assets upon the expiration of the Master Framework Agreements in 2014 or, in some circumstances, earlier; and

• Capgemini repaid $25 million (plus accrued interest) representing all amounts owed by Capgemini under the working capital loan provided by EFH Corp. in July 2004.

Under the Separation Agreements, the parties also entered into a mutual release of all claims under the Master Framework Agreements and related services agreements and the joint venture agreements, subject to certain defined exceptions.

EFH Corp. was incorporated in Texas in 1996. Our principal executive offices are located at Energy Plaza, 1601 Bryan Street, Dallas, TX 75201-3411. The telephone number of our principal executive offices is (214) 812-4600. Our Internet address is http://www.energyfutureholdings.com. Information on our web site does not constitute part of this prospectus.

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The Transactions

The Merger

On February 25, 2007, EFH Corp. entered into a merger agreement (the “Merger Agreement”) with Texas Holdings and Merger Sub, Texas Holdings’ wholly owned subsidiary, pursuant to which Texas Holdings acquired EFH Corp. on October 10, 2007 through a merger of Merger Sub with and into EFH Corp. Upon the effectiveness of the Merger, the shares of EFH Corp. common stock outstanding immediately prior to the Merger were cancelled and converted into the right to receive $69.25 per share in cash.

The acquisition of EFH Corp. by Texas Holdings was financed by the equity contributions and the debt financing described below. See also “—Sources and Uses” for more information.

Equity Contributions

At the closing of the Merger, Texas Holdings received an aggregate equity investment of approximately $8.3 billion. Investment funds affiliated with the Sponsor Group, or their respective assignees, contributed approximately $5.1 billion to Texas Holdings. The Sponsor Group obtained approximately $2.3 billion in equity investments from other existing investors in KKR’s and TPG’s private equity funds and other third party investors. Following the closing of the Merger, the Sponsor Group owned approximately 62% of the limited partnership units issued by Texas Holdings in connection with the Merger.

The equity contributions by the Sponsor Group and the Investors are referred to herein as the “Equity Contributions.”

Debt Financing

In connection with the Merger, we entered into the following debt financing arrangements:

• Senior secured credit facilities of TCEH (the “TCEH Senior Secured Facilities”), consisting of the following:

(a) a $16.45 billion senior secured initial term loan facility of TCEH (the “TCEH Initial Term Loan Facility”), which was used to fund the Merger and related transactions;

(b) a $4.1 billion senior secured delayed draw term loan facility of TCEH (the “TCEH Delayed Draw Term Loan Facility”), which is being used to fund capital expenditures and expenses related to the development of the three new lignite-fueled generation units and the environmental retrofit program;

(c) a $1.25 billion senior secured letter of credit facility of TCEH (the “TCEH Letter of Credit Facility”), which is being used for general corporate purposes;

(d) a $2.7 billion senior secured revolving credit facility of TCEH (the “TCEH Revolving Credit Facility”), which is being used for working capital and for other general corporate purposes; and

(e) a senior secured cash posting credit facility of TCEH (the “TCEH Commodity Collateral Posting Facility”), which is being used to fund all of the margin payments due on specified volumes of natural gas hedges;

• a $6.75 billion senior unsecured interim loan facility of TCEH (the “TCEH Senior Interim Facility”), which was used to fund the Merger and related transactions; and

• a $4.5 billion senior unsecured interim loan facility of EFH Corp. (the “EFH Senior Interim Facility”), which was used to fund the Merger and related transactions.

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In October 2007, TCEH and TCEH Finance, Inc. issued in a private offering $3,000,000,000 aggregate principal amount of 10.25% Senior Notes due 2015 (the “TCEH Series A cash-pay notes”). In December 2007, TCEH and TCEH Finance, Inc. issued in a private offering $2,000,000,000 aggregate principal amount of 10.25% Senior Notes due 2015, Series B (the “TCEH Series B cash-pay notes” and, together with the TCEH Series A cash-pay notes, the “TCEH cash-pay notes”), and $1,750,000,000 aggregate principal amount of 10.50%/11.25% Senior Toggle Notes due 2016 (the “TCEH toggle notes” and, together with the TCEH cash-pay notes, the “TCEH Notes”). The proceeds from the offering of TCEH Notes, along with cash on hand, were used by TCEH to repay in full the TCEH Senior Interim Facility.

In October 2007, EFH Corp. issued in a private offering $2,000,000,000 aggregate principal amount of 10.875% Senior Notes due 2017 (the “outstanding cash-pay notes”) and $2,500,000,000 aggregate principal amount of 11.250%/12.000% Senior Toggle Notes due 2017 (the “outstanding toggle notes” and, together with the outstanding cash-pay notes, the “outstanding notes”). The proceeds from the offering of the outstanding notes, along with cash on hand, were used by EFH Corp. to repay in full the EFH Senior Interim Facility.

We refer to the above, collectively, as the “Debt Financing.” See Note 17 to the 2007 year-end Financial Statements and Note 7 to the September 30, 2008 Financial Statements for a description of the material terms of each component of the Debt Financing and the Oncor Revolving Credit Facility (as defined below).

Concurrently with the transactions described above, Oncor entered into a $2.0 billion senior revolving credit facility (the “Oncor Revolving Credit Facility”), which may be increased by up to $500 million, subject to certain conditions, which is being used by Oncor for working capital and for other general corporate purposes. Borrowings under the Oncor Revolving Credit Facility were used for the refinancing of $800 million of outstanding notes issued by Oncor that became mandatorily redeemable by Oncor upon consummation of the Merger, repayment of approximately $385 million of borrowings under Oncor’s pre-Merger credit facilities, and approximately $113 million of borrowings were used to repurchase its receivables from TXU Receivables Company at the request of the funding institutions under the Receivables Program (as defined below) because Oncor is no longer an eligible originator under the Receivables Program. No portion of the Oncor Revolving Credit Facility was used to finance the Merger or the Debt Repayment (as defined below).

Also, in connection with the Merger, our accounts receivable securitization program (the “Receivables Program”), pursuant to which we sell trade accounts receivable to TXU Receivables Company, our consolidated wholly-owned bankruptcy-remote direct subsidiary, which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions, was amended. In connection with the amendment, the special purpose entities established by the financial institutions requested that Oncor repurchase all of the receivables it had previously sold to TXU Receivables Company. Accordingly, Oncor used a portion of its borrowings under the Oncor Revolving Credit Facility and cancelled a note due to it by TXU Receivables Company to repurchase its receivables.

In September 2007, we 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 (collectively, the “Specified Notes”). On the closing date of the Merger, we purchased an aggregate of $996 million, $247 million and $995 million of the principal amount of these notes, respectively. In connection with the Merger, we redeemed and repaid an aggregate of approximately $5.5 billion of our existing consolidated indebtedness (excluding indebtedness of Oncor), including debt that became payable upon the consummation of the Merger. We refer to the tender offers for the Specified Notes and the redemption and repayment of this outstanding indebtedness as the “Debt Repayment.”

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We refer to the transactions listed above, including the Merger and the application of the proceeds of the Equity Contributions and the Debt Financing as described under “—Sources and Uses,” as the “Transactions.”

Sources and Uses

The sources and uses of the funds for the Transactions are shown in the table below. For more information, see “Energy Future Holdings Corp. and Subsidiaries Unaudited Pro Forma Condensed Statement of Consolidated Income (Loss).”

Sources of funds:			Uses of funds:
(millions of dollars)
Cash and other sources	$	946	Equity purchase price (5)	$	32,384
TCEH Senior Secured Facilities (1)		18,982	Repayment of existing debt (6)		5,470
EFH Senior Interim Facility (2)		4,500	Transaction costs (7)		1,624
TCEH Senior Interim Facility (3)		6,750	Existing debt (8)		4,743
Equity contributions (4)		8,300
Existing debt (8)		4,743
Total sources of funds	$	44,221	Total uses of funds	$	44,221

(1) The TCEH Senior Secured Facilities consist of the following:

(a) the $16.45 billion TCEH Initial Term Loan Facility;

(b) the $4.1 billion TCEH Delayed Draw Term Loan Facility, of which $2.15 billion was drawn at the closing of the Merger;

(c) the $2.7 billion TCEH Revolving Credit Facility;

(d) the $1.25 billion TCEH Letter of Credit Facility, of which $1.25 billion was drawn but held as restricted cash at the closing of the Merger; and

(e) the TCEH Commodity Collateral Posting Facility, of which $382 million was actually drawn at the closing of the Merger.

(2) The proceeds from the offering of the outstanding notes, along with cash on hand, were used to repay in full the EFH Senior Interim Facility.

(3) The proceeds from the offering of TCEH Notes, along with cash on hand, were used to repay in full the TCEH Senior Interim Facility.

(4) Consists of Equity Contributions by the Sponsor Group, the Investors and management contributions.

(5) Reflects the amount of total consideration paid to holders of outstanding shares of EFH Corp.’s common stock, outstanding awards under the terms of EFH Corp.’s equity benefit plans, and common stock issuable upon conversion of EFH Corp.’s Floating Rate Convertible Senior Notes. The equity purchase price was determined based upon the sum of (A) 461.2 million shares of common stock multiplied by $69.25 per share; (B) 5.3 million shares of common stock issuable pursuant to the terms of outstanding awards under the terms of EFH Corp.’s equity benefit plans multiplied by $69.25 per share; and (C) 1.5 million shares of common stock issuable upon conversion of EFH Corp.’s Floating Rate Convertible Senior Notes due 2033 multiplied by $69.25 per share less $25 million principal amount of such notes.

(6) Repayment of existing indebtedness consists of the Debt Repayment described under “—The Transactions-Debt Financing.”

(7) Reflects fees and expenses associated with the Transactions, including placement and other financing fees, advisory fees, transactions fees paid to affiliates of the members of the Sponsor Group, and other transaction costs and professional fees.

(8) Excludes Oncor-related debt of $5,107 million as of September 30, 2007, including transition bonds and approximately $113 million related to repurchasing Oncor’s receivables previously sold under the Receivables Program.

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The Exchange Offers

In October 2007, EFH Corp. issued in a private offering the outstanding notes. The term “exchange cash-pay notes” refers to the 10.875% Senior Notes due 2017 and the term “exchange toggle notes” refers to the 11.250%/12.000% Senior Toggle Notes due 2017, each as registered under the Securities Act, and all of which collectively are referred to as the “exchange notes.” The term “cash-pay notes” collectively refers to the outstanding cash-pay notes and the exchange cash-pay notes and the term “toggle notes” collectively refers to the outstanding toggle notes and the exchange toggle notes. The term “notes” collectively refers to the outstanding notes and the exchange notes.

General In connection with the private offering, EFH Corp. and the guarantors of the outstanding notes entered into a registration rights agreement with the initial purchasers pursuant to which they agreed, among other things, to deliver this prospectus to you and to complete the exchange offers. You are entitled to exchange in the exchange offers your outstanding notes for the respective series of exchange notes that are identical in all material respects to the outstanding notes except:

• the exchange notes have been registered under the Securities Act;

• the exchange notes are not entitled to any registration rights which are applicable to the outstanding notes under the registration rights agreement; and

• the additional interest provisions of the registration rights agreement are not applicable.

The Exchange Offers EFH Corp. is offering to exchange:

• $2,000,000,000 aggregate principal amount of 10.875% Senior Notes due 2017 that have been registered under the Securities Act for any and all of its existing 10.875% Senior Notes due 2017; and

• $2,500,000,000 aggregate principal amount of 11.250%/12.000% Senior Toggle Notes due 2017 that have been registered under the Securities Act for any and all of its existing 11.250%/12.000% Senior Toggle Notes due 2017.

You may only exchange outstanding notes in minimum denominations of $2,000 and integral multiples of $1,000 in excess of $2,000.

Resale Based on an interpretation by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the exchange notes issued pursuant to the exchange offers in exchange for the outstanding notes may be offered for resale, resold and otherwise transferred by you (unless you are our “affiliate” within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that:

• you are acquiring the exchange notes in the ordinary course of your business; and

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• you have not engaged in, do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of the exchange notes.

If you are a broker-dealer and receive exchange notes for your own account in exchange for outstanding notes that you acquired as a result of market-making activities or other trading activities, you must acknowledge that you will deliver this prospectus in connection with any resale of the exchange notes. See “Plan of Distribution.”

Any holder of outstanding notes who:

• is our affiliate;

• does not acquire exchange notes in the ordinary course of its business; or

• tenders its outstanding notes in the exchange offers with the intention to participate, or for the purpose of participating, in a distribution of exchange notes

cannot rely on the position of the staff of the SEC enunciated in Morgan Stanley & Co. Incorporated (available June 5, 1991) and Exxon Capital Holdings Corporation (available May 13, 1988), as interpreted in Shearman & Sterling (available July 2, 1993), or similar no-action letters and, in the absence of an exemption therefrom, must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the exchange notes.

Expiration Date The exchange offers will expire at 11:59 p.m., New York City time, on                     , 2009, unless extended by EFH Corp. EFH Corp. currently does not intend to extend the expiration date.

Withdrawal You may withdraw the tender of your outstanding notes at any time prior to the expiration of the exchange offers. EFH Corp. will return to you any of your outstanding notes that are not accepted for any reason for exchange, without expense to you, promptly after the expiration or termination of the exchange offers.

Conditions to the Exchange Offers Each exchange offer is subject to customary conditions, which EFH Corp. may waive. See “The Exchange Offers—Conditions to the Exchange Offers.”

Procedures for Tendering Outstanding Notes If you wish to participate in any of the exchange offers, you must complete, sign and date the applicable accompanying letter of transmittal, or a facsimile of such letter of transmittal, according to the instructions contained in this prospectus and the letter of transmittal. You must then mail or otherwise deliver the letter of transmittal, or a facsimile of such letter of transmittal, together with your outstanding notes and any other required documents, to the exchange agent at the address set forth on the cover page of the letter of transmittal.

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If you hold outstanding notes through The Depository Trust Company (“DTC”) and wish to participate in any of the exchange offers, you must comply with the Automated Tender Offer Program procedures of DTC by which you will agree to be bound by the letter of transmittal. By signing, or agreeing to be bound by, the letter of transmittal, you will represent to us that, among other things:

• you are not an “affiliate” of EFH Corp. within the meaning of Rule 405 under the Securities Act or if you are an “affiliate”, you will comply with the registration and prospectus delivery requirements of the Securities Act;

• you do not have an arrangement or understanding with any person or entity to participate in a distribution (within the meaning of the Securities Act) of the exchange notes in violation of the provisions of the Securities Act;

• you are not engaged in, and do not intend to engage in, a distribution of the exchange notes;

• you are acquiring the exchange notes in the ordinary course of your business;

• if you are a broker-dealer, that you did not purchase the outstanding notes to be exchanged in the exchange offers from EFH Corp. or any of its affiliates; and

• you are not acting on behalf of any person who could not truthfully and completely make the above representations.

Special Procedures for Beneficial Owners If you are a beneficial owner of outstanding notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and you wish to tender those outstanding notes in any of the exchange offers, you should contact the registered holder promptly and instruct the registered holder to tender those outstanding notes on your behalf. If you wish to tender on your own behalf, you must, prior to completing and executing the letter of transmittal and delivering your outstanding notes, either make appropriate arrangements to register ownership of the outstanding notes in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time and may not be able to be completed prior to the expiration date.

Guaranteed Delivery Procedures If you wish to tender your outstanding notes and your outstanding notes are not immediately available, or you cannot deliver your outstanding notes, the letter of transmittal or any other required documents, or you cannot comply with the procedures under DTC’s Automated Tender Offer Program for transfer of book-entry interests prior to the expiration date, you must tender your outstanding notes according to the guaranteed delivery procedures set forth in this prospectus under “The Exchange Offers—Guaranteed Delivery Procedures.”

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Effect on Holders of Outstanding Notes As a result of the making of, and upon acceptance for exchange of all validly tendered outstanding notes pursuant to the terms of the exchange offers, EFH Corp. and the guarantors of the notes will have fulfilled a covenant under the registration rights agreement. Accordingly, there will be no increase in the applicable interest rate on the outstanding notes under the circumstances described in the registration rights agreement. If you do not tender your outstanding notes in any of the exchange offers, you will continue to be entitled to all the rights and limitations applicable to the outstanding notes as set forth in the indenture, except EFH Corp. and the guarantors of the notes will not have any further obligation to you to provide for the exchange and registration of untendered outstanding notes under the registration rights agreement. To the extent that outstanding notes are tendered and accepted in the exchange offers, the trading market for outstanding notes that are not so tendered and accepted could be adversely affected.

Consequences of Failure to Exchange All untendered outstanding notes will continue to be subject to the restrictions on transfer set forth in the outstanding notes and in the indenture. In general, the outstanding notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the exchange offers, EFH Corp. and the guarantors of the notes do not currently anticipate that they will register the outstanding notes under the Securities Act.

Certain U.S. Federal Income Tax Consequences The exchange of outstanding notes in the exchange offers will not be a taxable event for U.S. federal income tax purposes. See “Certain U.S. Federal Income Tax Consequences.”

Use of Proceeds We will not receive any cash proceeds from the issuance of the exchange notes in the exchange offers. See “Use of Proceeds.”

Exchange Agent The Bank of New York Mellon is the exchange agent for the exchange offers. The addresses and telephone numbers of the exchange agent are set forth in the section captioned “The Exchange Offers—Exchange Agent.”

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The Exchange Notes

The summary below describes the principal terms of the exchange notes. Certain of the terms and conditions described below are subject to important limitations and exceptions. The “Description of Notes” section of this prospectus contains more detailed descriptions of the terms and conditions of the outstanding notes and exchange notes. The exchange notes will have terms identical in all material respects to the respective series of outstanding notes, except that the exchange notes will not contain terms with respect to transfer restrictions, registration rights and additional interest for failure to observe certain obligations in the registration rights agreement.

Issuer EFH Corp.

Securities Offered $4,500,000,000 aggregate principal amount of exchange notes consisting of:

• $2,000,000,000 exchange cash-pay notes; and

• $2,500,000,000 exchange toggle notes.

Maturity Date November 1, 2017.

Interest Rate The exchange cash-pay notes will accrue interest at the rate of 10.875% per annum.

Until November 1, 2012 EFH Corp. may elect to pay interest on the exchange toggle notes, at EFH Corp.’s option:

• entirely in cash;

• by increasing the principal amount of the exchange toggle notes or by issuing new toggle notes (“Payment-In-Kind Interest” or “PIK interest”); or

• 50% in cash and 50% in PIK interest.

The exchange toggle notes will accrue cash interest at a rate of 11.250% per annum and PIK interest at a rate of 12.000% per annum.

For any interest period in which EFH Corp. elects to pay any PIK interest, as it did for the interest period related to the May 1, 2009 interest payment date, EFH Corp. will increase the principal amount of the exchange toggle notes or issue new toggle notes in an amount equal to the amount of PIK interest for the applicable interest payment period (rounded up to the nearest $1,000) to holders of the exchange toggle notes on the relevant record date.

Interest Payment Dates Interest on the exchange notes is payable on May 1 and November 1 of each year. Interest began to accrue from the original issue date of the outstanding notes.

Ranking The exchange notes will be EFH Corp.’s senior unsecured obligations and will:

• rank senior in right of payment to any future subordinated indebtedness of EFH Corp.;

• rank equally in right of payment with all of EFH Corp.’s existing and future senior unsecured indebtedness;

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• be 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 Guarantors (as defined below)); and

• rank effectively junior in right of payment to all future secured indebtedness of EFH Corp., to the extent of the assets securing that indebtedness.

As of September 30, 2008, (1) EFH Corp. did not have any senior secured indebtedness and (2) the outstanding notes were structurally subordinated to approximately $37.6 billion principal amount of indebtedness and other liabilities of EFH Corp.’s subsidiaries that are not guaranteeing the exchange notes, including all of TCEH’s and its subsidiaries’ indebtedness and all of Oncor’s and its subsidiaries’ indebtedness. As of September 30, 2008, TCEH had approximately $1.6 billion of additional available capacity under the TCEH Senior Secured Facilities (excluding amounts available under the TCEH Commodity Collateral Posting Facility), and Oncor had approximately $1.85 billion of additional available capacity under the Oncor Revolving Credit Facility.

Guarantees The exchange notes will be unconditionally guaranteed by Energy Future Competitive Holdings Company, the parent of TCEH (“EFC Holdings”), and Energy Future Intermediate Holding Company LLC (“Intermediate Holding” and, together with EFC Holdings, the “Guarantors”), the parent of Oncor Electric Delivery Holdings Company LLC (“Oncor Holdings”) and its subsidiaries (including Oncor), on a senior unsecured basis. The guarantees will rank equally with any unsecured senior indebtedness of the Guarantors and will be effectively junior to all secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. As of September 30, 2008, the guarantees ranked effectively junior to approximately $112 million of senior secured indebtedness of the Guarantors (excluding EFC Holdings’ secured guarantee of $23.6 billion of borrowings by TCEH under the TCEH Senior Secured Facilities and excluding $293 million of other secured indebtedness of TCEH). As of September 30, 2008, TCEH had approximately $1.6 billion of additional borrowing capacity available under the TCEH Senior Secured Facilities (excluding amounts available under the TCEH Commodity Collateral Posting Facility). The guarantees will be structurally junior to all indebtedness and other liabilities of EFH Corp.’s subsidiaries that do not guarantee the exchange notes. None of EFH Corp.’s other subsidiaries will guarantee the exchange notes. For the year ended December 31, 2007 and the nine months ended September 30, 2008, the non-guarantor EFH Corp. subsidiaries generated all of EFH Corp.’s consolidated total revenue. In addition, as of September 30, 2008, the non-guarantor EFH Corp. subsidiaries held substantially all of EFH Corp.’s consolidated total assets.

Security None.

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Optional Redemption EFH Corp. may redeem any of the exchange notes beginning on November 1, 2012 at the redemption prices set forth in this prospectus. EFH Corp. may also redeem any of the exchange 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. In addition, before November 1, 2010, EFH Corp. may redeem up to 35% of the aggregate principal amount of the exchange notes using the proceeds from certain equity offerings at the redemption price set forth in this prospectus. See “Description of the Notes—Optional Redemption.”

At the end of any “accrual period” (as defined in Section 1272(a)(5) of the Internal Revenue Code of 1986, as amended (the “Code”)) ending after the fifth anniversary of the issue date of the outstanding toggle notes (each, an “Optional Interest Repayment Date”), EFH Corp. may pay in cash, without duplication, all accrued and unpaid interest, if any, and all accrued but unpaid “original issue discount” (as defined in Section 1273(a)(1) of the Code) on each toggle note then outstanding up to, in the aggregate, the Optional Interest Repayment Amount (as defined below) (each such redemption, an “Optional Interest Repayment”). The “Optional Interest Repayment Amount” means, as of each Optional Interest Repayment Date, the excess, if any, of (a) the aggregate amount of accrued and unpaid interest and all accrued and unpaid “original issue discount” (as defined in Section 1273(a)(1) of the Code) with respect to the toggle notes, over (b) an amount equal to the product of (i) the “issue price” (as defined in Sections 1273(b) and 1274(a) of the Code) of the toggle notes multiplied by (ii) the “yield to maturity” (as defined in the Treasury Regulation Section 1.1272-1(b)(1)(i)) of the toggle notes, minus (c) $50,000,000.

Change of Control Offer Upon the occurrence of a change of control, you will have the right, as holders of the exchange notes, to require EFH Corp. to repurchase some or all of your exchange notes at 101% of their face amount, plus accrued and unpaid interest to the repurchase date. See “Description of the Notes—Repurchase at the Option of Holders—Change of Control.”

EFH Corp. may not be able to pay holders the required price for exchange notes they present to it at the time of a change of control, because:

• EFH Corp. may not have enough funds at that time; or

• the terms of EFH Corp.’s other indebtedness or any of its subsidiaries’ indebtedness, including under the TCEH Senior Secured Facilities, may prevent it from making such payment or receiving funds from its subsidiaries in an amount sufficient to fund such payment.

See “Risk Factors—Risks Relating to the Notes—We may not be able to repurchase the exchange notes upon a change of control.”

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Important Covenants The indenture governing the exchange notes contains covenants limiting EFH Corp.’s ability and the ability of each of its restricted subsidiaries to:

• incur additional debt or issue some types of preferred shares;

• pay dividends on or make other distributions in respect of EFH Corp.’s capital stock or make other restricted payments;

• make investments;

• sell assets;

• create liens on assets to secure debt;

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

• enter into certain transactions with its affiliates; and

• designate its subsidiaries as unrestricted subsidiaries.

These covenants are subject to a number of important limitations and exceptions. Oncor Holdings and its subsidiaries (including Oncor) are Unrestricted Subsidiaries under the indenture and, accordingly, are not subject to most of the restrictive covenants in the indenture. See “Description of the Notes.”

Voting The exchange cash-pay notes and the exchange toggle notes will be treated as a single class under the indenture. See “Description of the Notes.”

Original Issue Discount EFH Corp. has the option to pay interest on the exchange toggle notes in cash interest or PIK interest for any interest payment period prior to November 1, 2012. For U.S. federal income tax purposes, the existence of this option means that none of the interest payments on the exchange toggle notes will be “qualified stated interest”. Consequently, the exchange toggle notes will be treated as having been issued with “original issue discount”, and U.S. holders will be required to include the original issue discount in gross income for U.S. federal income tax purposes on a constant yield to maturity basis, regardless of whether interest is paid currently in cash. For more information, see “Certain U.S. Federal Income Tax Consequences.”

No Prior Market The exchange notes will be freely transferable, but will be new securities for which there will not initially be a market. Accordingly, we cannot assure you whether a market for the exchange notes will develop or as to the liquidity of any such market that may develop. The initial purchasers in the private offering of the outstanding notes have informed us that they currently intend to make a market in the exchange notes; however, they are not obligated to do so, and they may discontinue any such market-making activities at any time without notice.

Risk Factors You should consider carefully all of the information set forth in this prospectus prior to exchanging your outstanding notes. In particular, we urge you to consider carefully the factors set forth under the heading “Risk Factors.”

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Summary Historical and Unaudited Pro Forma Consolidated Financial Data of EFH Corp. and its Subsidiaries

The following table sets forth our summary historical consolidated financial data and summary unaudited pro forma consolidated financial data as of and for the periods indicated. The historical financial data as of December 31, 2007 (Successor) and 2006 (Predecessor) and 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) have been derived from our audited historical consolidated financial statements and related notes included elsewhere in this prospectus. The historical financial data as of December 31, 2005 has been derived from our audited historical consolidated financial statements that are not included in this prospectus. The historical financial data as of September 30, 2008 (Successor) and for the nine months ended September 30, 2008 (Successor) and 2007 (Predecessor) have been derived from our unaudited historical interim condensed consolidated financial statements and related notes included elsewhere in this prospectus which have been prepared on a basis consistent with our audited historical consolidated financial statements. In the opinion of our management, such unaudited interim financial data reflects all adjustments, consisting only of normal and recurring adjustments, necessary for the fair presentation of the results for those periods. The results of operations for the interim periods, for seasonal and other factors, are not necessarily indicative of the results to be expected for the full year or any future period.

The summary unaudited pro forma condensed consolidated financial data as of and for the year ended December 31, 2007 have been prepared to give effect to the Transactions in the manner described under “Energy Future Holdings Corp. Unaudited Pro Forma Condensed Consolidated Financial Statements” as if the Transactions had occurred on January 1, 2007. The pro forma adjustments are based upon available information and certain assumptions that we believe are reasonable. The summary unaudited pro forma consolidated financial data are for informational purposes only and do not purport to represent what our results of operations actually would have been if the Transactions had occurred at any date. In addition, this data does not purport to project the results of operations for any future period.

The summary historical and unaudited pro forma consolidated financial data should be read in conjunction with “Energy Future Holdings Corp. Unaudited Pro Forma Condensed Consolidated Financial Statements,” “Energy Future Holdings Corp. Selected Historical Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited and unaudited consolidated financial statements and related notes appearing elsewhere in this prospectus.

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	Historical										Pro Forma
	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007		Year Ended December 31,					Year Ended December 31, 2007
						2006		2005
	(millions of dollars, except ratios and per share amounts)
Statement of Income Data:
Operating revenues (a)	$	1,994		$	8,044	$	10,703	$	10,826		$	10,045
Income (loss) from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles		(1,361	)		699		2,465		1,775			(2,324	)
Income from discontinued operations, net of tax effect		1			24		87		5
Extraordinary gain (loss), net of tax effect		—			—		—		(50	)
Cumulative effect of changes in accounting principles, net of tax effect		—			—		—		(8	)
Preference stock dividends		—			—		—		10
Net income (loss) available for common stock		(1,360	)		723		2,552		1,712
Dividends declared per share	$	—		$	1.30	$	1.67	$	1.26
Ratio of earnings to fixed charges (b)		—			2.30		5.11		3.80			—
Ratio of earnings to combined fixed charges and preference dividends (b)		—			2.30		5.11		3.74			—

	Successor		Predecessor
	December 31, 2007		December 31,
			2006		2005
	(millions of dollars)
Balance Sheet Data:
Total assets—end of year (c)	$	64,804	$	27,216	$	27,978
Property, plant & equipment—net—end of year		28,650		18,569		17,006
Total goodwill and intangible assets		27,319		729		728
Total debt (d)		40,834		12,607		13,380
Total preferred stock and stock of subsidiaries (e)		—		—		—
Total shareholders’ equity		6,685		2,140		475

	Historical
	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
	(millions of dollars, except ratios)
Statement of Cash Flows Data:
Cash flows provided by (used in) operating activities from continuing operations	$	(450	)	$	2,265		$	4,954		$	2,793
Cash flows provided by (used in) financing activities from continuing operations		33,865			1,394			(2,332	)		(1,563	)
Cash flows provided by (used in) investing activities from continuing operations		(34,563	)		(2,283	)		(2,664	)		(1,038	)
Other Financial Data:
Capital expenditures, including nuclear fuel	$	707		$	2,395		$	2,297		$	1,104

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

(b) 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. For pro forma year ended December 31, 2007, fixed charges and combined fixed charges and preference dividends exceeded earnings by $3.583 billion.

(c) The total assets shown above reflect the change in presentation related to EFH Corp.’s adoption of FIN 39-1 as discussed in Note 1 to the 2007 year-end Financial Statements. Such change in presentation resulted in an increase of $1.020 billion, $1.383 billion and $2.439 billion in EFH Corp.’s total assets and total liabilities as of December 31, 2007, 2006 and 2005, respectively, as compared to amounts previously reported in the EFH Corp. Annual Report on Form 10-K for the year ended December 31, 2007.

(d) Includes long-term debt, including amounts due currently, and short-term borrowings.

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

	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
	(millions of dollars, except ratios and per share amounts)
Statement of Income Data:
Operating revenues (a)	$	9,001		$	7,743
Income (loss) from continuing operations		(983	)		591
Income from discontinued operations, net of tax effect		—			24
Net income (loss) available for common stock		(983	)		615
Dividends declared per share	$	—		$	1.30
Ratio of earnings to fixed charges (b)		—			2.11
Ratio of earnings to combined fixed charges and preference dividends (b)		—			2.11

	Successor
	September 30, 2008
	(millions of dollars)
Balance Sheet Data:
Total assets—end of period	$	67,491
Property, plant & equipment—net—end of period		29,600
Total goodwill and intangible assets		26,495
Total debt (c)		43,903
Total preferred stock and stock of subsidiaries (d)		—
Total shareholders’ equity		5,633

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	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
	(millions of dollars)
Statement of Cash Flows Data:
Cash flows provided by operating activities from continuing operations	$	957		$	1,555
Cash flows provided by financing activities from continuing operations		3,052			1,323
Cash flows used in investing activities from continuing operations		(2,374	)		(2,285	)
Other Financial Information:
Capital expenditures, including nuclear fuel		2,179			2,450

(a) The operating revenues shown above reflect the change in classification for commodity hedging and trading activities discussed in Note 1 to the September 30, 2008 Financial Statements that resulted in an increase in operating revenues of $607 million for the nine months ended September 30, 2007.

(b) Fixed charges and combined fixed charges and preference dividends exceeded earnings by $1.445 billion for the nine months ended September 30, 2008.

(c) Includes long-term debt, including amounts due currently, and short-term borrowings.

(d) Preferred stock outstanding at September 30, 2008 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, a change in presentation related to EFH Corp.’s adoption of FIN 39-1 and a change in classification to report the results of commodity hedging and trading activities on a separate line in the income statement instead of within operating revenues. (See Note 1 to the 2007 year-end Financial Statements “Basis of Presentation” and Note 1 to the September 30, 2008 Financial Statements “Basis of Presentation.”) The consolidated financial statements of the Successor reflect the application of “purchase accounting.”

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RISK FACTORS

You should carefully consider the risk factors set forth below as well as the other information contained in this prospectus before deciding to tender your outstanding notes in the exchange offers. Any of the following risks could materially and adversely affect our business, financial condition, operating results or cash flow; however, the following risks are not our only risks. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial also may materially and adversely affect our business, financial condition or results of operations. In such a case, the trading price of the exchange notes could decline or we may not be able to make payments of interest and principal on the exchange notes, and you may lose all or part of your original investment.

Risks Related to the Exchange Offers

There may be adverse consequences if you do not exchange your outstanding notes.

If you do not exchange your outstanding notes for exchange notes in the exchange offers, you will continue to be subject to restrictions on transfer of your outstanding notes as set forth in the offering memorandum distributed in connection with the private offering of the outstanding notes. In general, the outstanding notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the outstanding notes under the Securities Act. You should refer to “Prospectus Summary—The Exchange Offers” and “The Exchange Offers” for information about how to tender your outstanding notes.

The tender of outstanding notes under the exchange offers will reduce the outstanding amount of the outstanding notes, which may have an adverse effect upon, and increase the volatility of, the market prices of the outstanding notes due to a reduction in liquidity.

Your ability to transfer the exchange notes may be limited if there is absence of an active trading market, and an active trading market may not develop for the exchange notes.

We are offering the exchange notes to the holders of the outstanding notes. The outstanding notes were offered and sold in October 2007 to institutional investors and are eligible for trading in the PORTAL market.

We do not intend to apply for a listing of the exchange notes on a securities exchange or on any automated dealer quotation system. There is currently no established market for the exchange notes, and we cannot assure you as to the liquidity of markets that may develop for the exchange notes, your ability to sell the exchange notes or the price at which you would be able to sell the exchange notes. If such markets were to exist, the exchange notes could trade at prices that may be lower than their principal amount or purchase price depending on many factors, including prevailing interest rates, the market for similar notes, our financial and operating performance and other factors. The initial purchasers in the private offering of the outstanding notes have advised us that they currently intend to make a market with respect to the exchange notes. However, these initial purchasers are not obligated to do so, and any market making with respect to the exchange notes may be discontinued at any time without notice. In addition, such market making activity may be limited during the pendency of the exchange offers or the effectiveness of a shelf registration statement in lieu thereof. Therefore, an active market for the exchange notes may not develop or, if developed, may not continue. Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the exchange notes. The market, if any, for the exchange notes may experience similar disruptions and any such disruptions may adversely affect the prices at which you may sell your exchange notes.

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Certain persons who participate in the exchange offers must deliver a prospectus in connection with resales of the exchange notes.

Based on interpretations of the staff of the SEC contained in Exxon Capital Holdings Corp., SEC no-action letter (April 13, 1988), Morgan Stanley & Co. Inc., SEC no-action letter (June 5, 1991) and Shearman & Sterling, SEC no-action letter (July 2, 1983), we believe that you may offer for resale, resell or otherwise transfer the exchange notes without compliance with the registration and prospectus delivery requirements of the Securities Act. However, in some instances described in this prospectus under “Plan of Distribution,” certain holders of exchange notes will remain obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer the exchange notes. If such a holder transfers any exchange notes without delivering a prospectus meeting the requirements of the Securities Act or without an applicable exemption from registration under the Securities Act, such a holder may incur liability under the Securities Act. We do not and will not assume, or indemnify such a holder against, this liability.

Risks Related to the Notes

The following risks apply to the outstanding notes and will apply equally to the exchange notes.

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

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

If cash flows and capital resources are insufficient to fund our debt service obligations, we could face substantial liquidity problems and might be forced to reduce or delay investments and capital expenditures, or to dispose of assets or operations, seek additional capital or restructure or refinance indebtedness, including the notes. These alternative measures may not be successful or may not be adequate for us to meet our debt service obligations then due. Additionally, our debt agreements, including the indenture governing the notes, limit the use of the proceeds from any disposition; as a result, we may not be allowed, under these documents, to use proceeds from such dispositions to satisfy all current debt service obligations.

If we or any of our subsidiaries defaults on obligations to pay indebtedness, we may not be able to make payments on the notes.

Any default under our debt agreements that is not waived by the required lenders or noteholders, and the remedies sought by the holders of such indebtedness, could prevent us from paying principal, premium, if any, and interest on the notes and substantially decrease the market value of the notes. If our subsidiaries are unable to generate sufficient cash flows and we are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our and their indebtedness, or if we or they otherwise fail to comply with the various covenants, including any financial and operating covenants, in the instruments governing our and their indebtedness, we or they could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, and/or the lenders could elect to terminate their commitments thereunder, cease making further loans and, in the case of the lenders under the TCEH Senior Secured Facilities, institute foreclosure proceedings against the pledged assets, and we or they could be forced into bankruptcy or liquidation. If the operating performance of our subsidiaries declines, we or certain of our subsidiaries, including TCEH, may in the future need to obtain waivers from the required lenders to avoid being in default. If our subsidiaries breach the covenants under the TCEH Senior Secured Facilities or the indenture governing the TCEH Notes and seek a waiver, they may not be able to obtain a waiver from the

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required lenders. If this occurs, they would be in default under the instrument governing that indebtedness, the lenders could exercise their rights, as described above, and such subsidiaries could be forced into bankruptcy or liquidation.

We may not be able to repurchase the notes upon a change of control.

Upon the occurrence of specific kinds of change of control events, we will be required to offer to repurchase all notes at 101% of their principal amount plus accrued and unpaid interest. The source of funds for any such purchase of the notes will be our available cash or cash generated from our subsidiaries’ operations or other sources, including borrowings, sales of assets or sales of equity. We may not be able to repurchase the notes upon a change of control because we may not have sufficient financial resources to purchase all of the notes that are tendered upon a change of control. Further, we may be restricted under the terms of TCEH’s debt agreements from receiving TCEH funds sufficient to repurchase all of the notes tendered by holders upon a change of control. Accordingly, we may not be able to satisfy our obligations to purchase the notes unless we are able to refinance or obtain waivers under the instruments governing that indebtedness. Our failure to repurchase the notes upon a change of control would cause a default under the indenture and a cross-default under certain of our other debt agreements. The instruments governing the TCEH Senior Secured Facilities also provide that a change of control will be a default that permits the lenders thereunder to accelerate the maturity of borrowings thereunder. Any of our future debt agreements may contain similar provisions.

You will be required to pay U.S. federal income tax on the toggle notes, whether we pay interest on the toggle notes in cash or PIK interest.

We have the option to pay interest on the toggle notes in cash or PIK interest. For U.S. federal income tax purposes, the existence of this option means that none of the interest payments on the toggle notes are qualified stated interest for U.S. federal income tax purposes (as defined under “Certain U.S. Federal Income Tax Consequences—Certain Tax Consequences to U.S. Holders—Toggle Notes”). Consequently, the toggle notes are treated as having been issued with original issue discount for U.S. federal income tax purposes, and U.S. holders (as defined under “Certain U.S. Federal Income Tax Consequences”) will be required to include the original issue discount in gross income on a constant yield to maturity basis, regardless of whether interest is paid currently in cash. See “Certain U.S. Federal Income Tax Consequences—Certain Tax Consequences to U.S. Holders—Toggle Notes.”

The voting interest of the holders of the notes will be diluted.

The cash-pay notes and the toggle notes are each a separate series of notes under the indenture but will be treated as a single class of securities under the indenture, except as otherwise stated herein. The cash-pay notes and the toggle notes will be treated as a single class for amendments and waivers affecting all such notes and for actions requiring the consent of holders of the notes, such as declaring certain defaults under the indenture governing the notes or accelerating the amounts due under the notes. Consequently, certain actions, including amendments and waivers, which will affect the holders of one series of the notes, may be accomplished whether or not the holders of that series of the notes consent to such action. As a result, the individual voting interest of the holders of the notes will be accordingly diluted.

EFC Holdings’ guarantee is effectively subordinated to those lenders who have a security interest in our assets.

EFC Holdings’ obligations under its guarantee of the notes are unsecured, but its obligations under its guarantee of the TCEH Senior Secured Facilities are secured by a security interest in substantially all of its tangible and intangible assets. If EFC Holdings were unable to pay under its guarantee of the TCEH Senior Secured Facilities, the lenders could foreclose on the pledged assets described above to the exclusion of holders of the notes, even if an event of default exists under the indenture governing the notes at such time. In any such event, because the guarantee of the notes will not be secured by any of EFC Holdings’ assets or the equity

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interests in EFC Holdings, it is possible that there would be no assets remaining from which your claims as a noteholder could be satisfied or, if any assets remained, they might be insufficient to fully satisfy your claims as a noteholder under such guarantee. See Note 17 to the 2007 year-end Financial Statements and Note 7 to the September 30, 2008 Financial Statements.

As of September 30, 2008, EFC Holdings had $24.0 billion of secured indebtedness, consisting primarily of $23.6 billion in the TCEH Senior Secured Facilities, and TCEH had approximately $1.6 billion of available borrowing capacity under the TCEH Senior Secured Facilities (excluding amounts available under the TCEH Commodity Collateral Posting Facility).

Federal and state statutes allow courts, under specific circumstances, to void guarantees, subordinate claims in respect of guarantees and require note holders to return payments received from the guarantors.

The notes are guaranteed by EFC Holdings and Intermediate Holding. The issuance of the guarantees by the guarantors may be subject to review under state and federal laws if a bankruptcy, liquidation or reorganization case or a lawsuit, including in circumstances in which bankruptcy is not involved, were commenced at some future date by, or on behalf of, our unpaid creditors or the unpaid creditors of a guarantor. Under the federal bankruptcy laws and comparable provisions of state fraudulent transfer laws, a court may void or otherwise decline to enforce a guarantor’s guarantee, or subordinate such guarantee to such guarantor’s existing and future indebtedness. While the relevant laws may vary from state to state, a court might do so if it found that when a guarantor entered into its guarantee or, in some states, when payments became due under such guarantee, such guarantor received less than reasonably equivalent value or fair consideration and either:

• was insolvent or rendered insolvent by reason of such incurrence;

• was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

• intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they mature.

The court might also void a guarantee, without regard to the above factors, if the court found that a guarantor entered into its guarantee with actual intent to hinder, delay or defraud its creditors. In addition, any payment by a guarantor pursuant to its guarantee could be voided and required to be returned to such guarantor or to a fund for the benefit of such guarantor’s creditors. A court would likely find that a guarantor did not receive reasonably equivalent value or fair consideration for such guarantee if such guarantor did not substantially benefit directly or indirectly from the issuance of the notes. If a court were to void a guarantee, you would no longer have a claim against the guarantor. Sufficient funds to repay the notes may not be available from other sources. In addition, the court might direct you to repay any amounts that you already received from a guarantor. The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a guarantor would be considered insolvent if:

• the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;

• if the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

• it could not pay its debts as they become due.

To the extent a court voids any of the guarantees as a fraudulent transfer or holds any of the guarantees unenforceable for any other reason, holders of notes would cease to have any direct claim against the applicable

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guarantor. If a court were to take this action, a guarantor’s assets would be applied first to satisfy such guarantor’s liabilities, if any, before any portion of its assets could be applied to the payment of the notes. Each guarantee contains a provision intended to limit the guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent transfer. This provision may not be effective to protect the guarantees from being voided under fraudulent transfer law, or may reduce the guarantor’s obligation to an amount that effectively makes the guarantee worthless.

The majority of our subsidiaries do not guarantee the notes.

The notes are guaranteed on a senior unsecured basis by EFC Holdings and Intermediate Holding, but not by any of our other current subsidiaries. EFC Holdings and Intermediate Holding are holding companies. Neither EFC Holdings nor Intermediate Holding has any operations and each relies on distributions from its subsidiaries. However, the historical consolidated financial statements and the pro forma condensed combined financial information included in this prospectus include all of our subsidiaries. Our non-guarantor subsidiaries generated all of our revenues for the year ended December 31, 2007 and the nine-month period ended September 30, 2008, and as of September 30, 2008, our non-guarantor subsidiaries held substantially all of our total assets. See Note 29 to our 2007 year-end Financial Statements and Note 17 to the September 30, 2008 Financial Statements included elsewhere in this prospectus.

Our non-guarantor subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due pursuant to the notes, or to make any funds available therefore, whether by dividends, loans, distributions or other payments. Any right that EFH Corp., EFC Holdings or Intermediate Holding has to receive any assets of any of the non-guarantor subsidiaries upon the liquidation or reorganization of those subsidiaries, and the consequent rights of holders of notes to realize proceeds from the same of any of those subsidiaries’ assets, will be effectively subordinated to the claims of that subsidiary’s preferred equity holders and creditors, including trade creditors and holders of debt of that subsidiary.

The interests of our controlling stockholders may differ from the interests of the holders of the notes.

The Sponsor Group indirectly owns approximately 60% of our 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 our operations, plans, strategies, finances and structure, including whether to enter into any corporate transaction and will have the ability to prevent any transaction that requires the approval of our stockholders.

The interests of these persons may differ from your interests in material respects. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of the Sponsor Group, as equity holders, might conflict with your interests as a note holder. The Sponsor Group may also have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in their judgment, could enhance their equity investments, even though such transactions might involve risks to you as a note holder. Additionally, the indenture governing the notes permits us to pay advisory fees, dividends or make other restricted payments under certain circumstances, and the Sponsor Group may have an interest in our doing so.

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Risks Related to Our Indebtedness and Debt Agreements

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

We are highly leveraged. As of September 30, 2008, our consolidated principal amount of debt (short term borrowings and long-term debt, including amounts due currently) totaled $44.8 billion. Our substantial leverage could have important consequences, including:

• making it more difficult for us to make payments on our indebtedness, including the exchange notes;

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

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

• exposing us to the risk of increased interest rates because certain of our borrowings are at variable rates of interest;

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

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

• limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to competitors who are less highly leveraged and who therefore, may be able to take advantage of opportunities that our substantial leverage prevents us from exploring.

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

We may be able to incur additional indebtedness in the future. Although our 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 our existing debt levels, the related risks that we now face would intensify.

Increases in interest rates may negatively impact our operating results and financial condition.

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

At September 30, 2008, we had $3.6 billion aggregate principal amount of variable rate long-term indebtedness (excluding $1.25 billion of long-term borrowings associated with the TCEH Letter of Credit Facility that are invested at a variable rate), taking into account interest rate swaps that fix the interest rate on $16.55 billion in notional amount of variable rate indebtedness. As a result, as of September 30, 2008, the impact of a 100 basis point increase in interest rates would increase our annual interest expense by approximately $36 million. See discussion of interest rate swap transactions in “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Significant Developments-Interest Rate Swap Transactions”.

Our pro forma interest expense for the year ended December 31, 2007 was $3.6 billion.

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Our debt agreements contain restrictions that limit our flexibility in operating our businesses.

Our debt agreements contain various covenants and other restrictions that limit our ability to engage in specified types of transactions, and which may adversely affect our ability to operate our businesses. These covenants and other restrictions limit our and our 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 our assets, and

• enter into transactions with our affiliates.

There are a number of important limitations and exceptions to these covenants and other restrictions. You should read “Description of the Notes” and Note 17 to the 2007 year-end Financial Statements and Note 7 to the September 30, 2008 Financial Statements for a description of these covenants and other restrictions.

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

A breach of any of these covenants or restrictions could result in an event of default under one or more of our 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 our other indebtedness. If we were 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, we may not have sufficient assets and funds to repay those borrowings and the exchange notes.

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

• Oncor being treated as an Unrestricted Subsidiary with respect to the notes;

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

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

Accordingly, Oncor’s assets will not be available to repay any of the notes, the TCEH Senior Secured Facilities or the TCEH Notes. See the subsections relating to the “Regulated Delivery Segment” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information regarding the results of operations of Oncor.

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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 September 30, 2008, TCEH and its subsidiaries held approximately 77% of our consolidated assets. Accordingly, we depend upon TCEH for a significant amount of our cash flows and ability to pay our obligations. For the year ended December 31, 2007 and the nine-month period ended September 30, 2008, TCEH and its subsidiaries represented 85% and 87%, respectively, of our consolidated revenues. However, under the terms of TCEH’s debt agreements, TCEH is restricted from making certain payments to us, except in limited circumstances. In addition, TCEH is prohibited from making certain loans to us if certain events of default under the debt agreements have occurred and are continuing.

Risks Related to Our Structure

We are a holding company and our obligations are structurally subordinated to existing and future liabilities and preferred stock of our subsidiaries.

Our cash flows and ability to meet our obligations are largely dependent upon the earnings of our subsidiaries and the payment of such earnings to us in the form of dividends, distributions, loans or otherwise, and repayment of loans or advances from us. These subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. Any decision by a subsidiary to provide us with funds for our 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.

Because we are a holding company, our obligations to our creditors are structurally subordinated to all existing and future liabilities and existing and future preferred stock of our subsidiaries. Therefore, our rights and the rights of our 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 we may be a creditor with recognized claims against any such subsidiary, our 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 us. Subject to restrictions contained in financing arrangements, our subsidiaries may incur additional indebtedness and other liabilities.

Oncor may not make any distributions to EFH Corp.

Upon the consummation of the Merger, EFH Corp. and Oncor implemented certain structural and operational “ring-fencing” measures based on principles articulated by rating agencies and commitments made by Texas Holdings and Oncor to the PUCT and the FERC to further separate Oncor from Texas Holdings and its other subsidiaries. These measures were put into place to mitigate Oncor’s credit exposure to those entities and to reduce the risk that the assets and liabilities of Oncor would be substantively consolidated with the assets and liabilities of Texas Holdings or any of its other subsidiaries in the event of a bankruptcy of one or more of those entities.

You should not look to the assets, financial condition or results of operations of Oncor as a source for payments of interest or principal on the notes. Oncor Holdings and its subsidiaries are “Unrestricted Subsidiaries” as defined in the indenture governing the notes and, accordingly, will not be subject to the

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restrictive covenants in the indenture. However, you should be aware that our consolidated financial information presented elsewhere in this prospectus includes the results of Oncor for all periods. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information regarding the results of operations of Oncor.

As part of the ring-fencing measures implemented by us 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, acting by majority vote, and, during certain periods, any director designated by Texas Transmission Investment LLC the express right to prevent distributions from Oncor if they determine that it is in the best interests of Oncor to retain such amounts to meet expected future requirements. Accordingly, there can be no assurance that Oncor will make any distributions to EFH Corp.

In addition, Oncor’s organizational documents prohibit Oncor from making any distribution to EFH Corp. so long as and to the extent that such distribution would cause Oncor’s debt-to-equity ratio for regulatory purposes of Oncor to be above the debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. In September 2008, Oncor and several other ERCOT utilities filed with the PUCT a joint Competitive Renewable Energy Zones (CREZ) Transmission Plan, which includes the joint parties’ plans to consult and operate all of the CREZ transmission facilities. As part of this filing, Oncor proposes to build at least 1,000 miles of transmission lines and facilities in and around Oncor’s service territory, which based on ERCOT’s estimates will require an investment of more than $2 billion (see discussion under “Regulation and Rates-Matters with the PUCT-Competitive Renewable Energy Zones (CREZ)). If Oncor’s proposal is accepted, it is likely Oncor will incur significant additional debt. In addition, Oncor may incur additional debt in connection with other investments in infrastructure or technology. Accordingly, there can be no assurance that Oncor’s debt-to-equity ratio for regulatory purposes of Oncor will not exceed the debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, thereby restricting Oncor from making any distributions to EFH Corp.

Risks Related to Our Businesses

Our businesses are subject to ongoing complex governmental regulations and legislation that have impacted, and may in the future impact, our businesses and/or results of operations.

Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory initiatives regarding the restructuring of the energy industry, including competition in the generation and sale of electricity. We will need to continually adapt to these changes. For example, the Texas retail electricity market became competitive in January 2002, and the introduction of competition has resulted in, and may continue to result in, declines in customer counts and sales volumes.

Our businesses are subject to changes in state and federal laws (including PURA, the Federal Power Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act 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

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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 our businesses.

In 2007, the Texas legislature adopted legislation that likely requires prior PUCT approval for certain direct or indirect dispositions of Oncor, and ensures that the PUCT will have authority to enforce commitments made in a filing on or after May 1, 2007 under PURA Section 14.101 (such as the filing made by Texas Holdings and Oncor on April 25, 2007). Several pieces of legislation were introduced in the Texas legislature during 2007 that, if passed, may have had a material impact on us and our financial prospects, including, for example, legislation that would have:

• required us to separate our 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 we 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 we would not have considered to be full value, and

• given new authority to the PUCT to cap retail electricity 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 us and our 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 our business and financial prospects.

Litigation or legal proceedings could expose us to significant liabilities and reputation damage and have a material adverse effect on our results of operations, and the litigation environment in which we operate poses a significant risk to our businesses.

We are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, environmental and injuries and damages issues, among other matters, such as challenges (to which we 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. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these assessments and estimates, we establish reserves and disclose 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 our 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. We use legal and appropriate means to contest litigation threatened or filed against us, but the litigation environment in the state of Texas poses a significant business risk.

We are also exposed to the risk that we may become the subject of regulatory investigations. See “Our Business—Legal and Administrative Proceedings—Regulatory Investigations and Reviews.”

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

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

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In most retail electric markets, TXU Energy’s principal competitor may be the incumbent retail electric provider. The incumbent retail electric provider has the advantage of long-standing relationships with its customers, including well-known brand recognition.

In addition to competition from the incumbent retail electric provider, 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.

Our 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.

We are not guaranteed any rate of return on capital investments in our competitive businesses. We market and trade electricity and natural gas, including electricity from our own generation facilities and generation contracted from third parties, as part of our wholesale markets operation. Our results of operations depend in large part upon market prices for electricity, natural gas, uranium and coal in our 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 is providing price protection to these customers through December 2008. In addition, TXU Energy committed in 2006 to not increase prices above then current levels through 2009 for qualifying residential customers who remain on certain plans with rates that were then equal to the price-to-beat rate.

Some of the fuel for our 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 we can obtain for electricity sales may not change at the same rate as changes in fuel costs. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting obligations.

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

• 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 our generation facilities or those of competitors;

• changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;

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• natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and

• federal, state and local energy, environmental and other regulation and legislation.

All of 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 our supply volumes in 2007 and the first nine months of 2008, 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.

Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging transactions may not work as planned or hedge counterparties may default on their obligations.

We cannot fully hedge the risk associated with changes in natural gas prices or market heat rates because of the expected useful life of our generation assets and the size of our position relative to market liquidity. To the extent we have unhedged positions, fluctuating commodity prices and/or market heat rates can materially impact our results of operations and financial position, either favorably or unfavorably.

To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portions of purchase and sale commitments, 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, we routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Although we devote a considerable amount of time and effort to the establishment of risk management procedures, as well as the ongoing review of the implementation of these procedures, the procedures in place may not always function as planned and cannot eliminate all the risks associated with these activities. As a result of these and other factors, we cannot precisely predict the impact that risk management decisions may have on our businesses, results of operations or financial position.

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

We 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;

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• 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.

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

• Operational Risk—Operations at any nuclear generation 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 U.S. and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impact, and property damage. Any accident, or perceived accident, could result in significant liabilities and damage our reputation. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage.

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

The operation and maintenance of electricity generation and delivery facilities involves many risks, including, as applicable, start-up risks, breakdown or failure of facilities, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source or the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in lost revenues and/or increased expenses. A significant number of our facilities were constructed many years ago. In particular, older generating equipment and transmission and distribution equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep operating at peak efficiency or reliability. The risk of increased maintenance and capital expenditures arises from (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, our ability to successfully and timely complete capital improvements to existing facilities or other capital projects is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs and/or the write-off of our investment in the project or improvement.

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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 our control.

Our cost of compliance with environmental laws and regulations and our commitments, and the cost of compliance with new environmental laws, regulations or commitments could materially adversely affect our results of operations and financial condition.

We are subject to extensive environmental regulation by governmental authorities. In operating our facilities, we are required to comply with numerous environmental laws and regulations and to obtain numerous governmental permits. We may incur significant additional costs beyond those currently contemplated to comply with these requirements. If we fail to comply with these requirements, we could be subject to civil or criminal liabilities and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions, all of which could result in significant additional costs beyond those currently contemplated to comply with existing requirements.

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

We have formed a Sustainable Energy Advisory Board that advises us in our pursuit of technology development opportunities that, among other things, are designed to reduce our impact on the environment. Adoption of Sustainable Energy Advisory Board recommendations may cause us to incur significant costs in addition to the costs referenced above.

We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals or if we fail to obtain, maintain or comply with any such approval, the operation and/or construction of our facilities could be stopped, curtailed or modified or become subject to additional costs.

In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that we have acquired, leased or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against us or fail to meet its indemnification obligations to us.

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 U.S. Congress and, in April 2007, the U.S. 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 we continue to assess the financial and operational risks posed by possible future legislative changes pertaining to greenhouse gas emissions, we are currently unable to predict any future impact from these changes on our financial condition and operations.

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

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

In 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. The final stipulation required 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. Oncor filed the rate case (Docket No. 35717) in June 2008.

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 we believe Oncor’s rates are just and reasonable, we cannot predict the results of any rate case, including the rate case filed in June 2008.

Our 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 our financial condition and results of operations.

There can be no guarantee that the execution of our growth strategy will be successful. As discussed below, our 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 our growth strategy, including causing management to change the strategy. Even if we are able to execute our 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, constructing, commissioning and starting-up such facilities. To the extent construction is not managed efficiently and to a timely conclusion, cost overruns may occur, resulting in the overall program costing significantly more than anticipated. This may also result in delays in the expected online dates for the facilities resulting in less overall income than projected. While 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, commissioning and starting-up these new facilities.

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

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generation development program, each of these permits is subject to ongoing litigation. See “Our Business—Legal and Administrative Proceedings—Litigation Related to Generation Development” for further details regarding such 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 a significant amount of new generation assets in ERCOT, market prices of power could fall such that the new generation capacity becomes uneconomical. In addition, any unanticipated reduction in wholesale electricity prices, market heat rates and natural gas prices, which could occur for a variety of reasons, could adversely impact this program. Even if 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, we are subject to the risk that our outsourcing arrangements for business support services may not produce the desired cost savings. In cases where any such outsourcing arrangement is terminated, such as our joint venture outsourcing arrangement with Capgemini, or if any party performing such business support services becomes financially unable to perform its obligations, we 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 our 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 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 of such services.

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

In connection with the Merger, TXU Energy implemented a 15% price reduction through December 31, 2008 for residential customers in our 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 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. 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 its financial prospects.

Changes in technology may reduce the value of our generation plants and/or Oncor’s electric delivery facilities and may significantly impact our businesses in other ways as well.

Research and development activities are ongoing to improve existing and alternative technologies to produce electricity, including gas turbines, fuel cells, microturbines 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 U.S., the rate of construction and development of new, more efficient generation facilities may exceed increases

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in demand in some regional electric markets. Consequently, where we have facilities, the profitability and market value of our 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 our 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, our revenues could be reduced.

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

A significant amount of investment in wind generation in the ERCOT market over the past few years has increased overall wind power generation capacity. Generally, the increased capacity has led to lower wholesale electricity prices (driven by lower market heat rates) in the zones at or near wind generation development, especially in, but not exclusive to, the West Zone where most of the new wind power generation is located. As a result, the profitability of our generation facilities and power purchase contracts, including certain wind generation power purchase contracts, have been impacted by the effects of the wind power generation, and the value could significantly decrease if wind power generation has a material sustained effect on ERCOT market heat rates.

Our revenues and results of operations may be adversely impacted if ERCOT transitions the current zonal market structure to a nodal wholesale market.

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

Our 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, we are subject to settlement adjustments from ERCOT related to prior periods, which may result in charges or credits impacting our future reported results of operations.

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

We derive substantially all of our revenues from operations in the ERCOT market, which covers approximately 75% of the geographical area in the state of Texas. As a result, regardless of the state of the economy in areas outside the ERCOT market, economic weakness in the ERCOT market could lead to reduced demand for electricity in the ERCOT market. Such a reduction could have a material negative impact on our results of operations and financial condition.

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

Downgrades in our or any of our 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 and TCEH’s long term debt ratings. On November 3, 2008, Moody’s changed the rating outlook for EFH Corp. and TCEH to negative from stable, stating that the change was primarily related to the decision to elect the PIK interest option on the toggle notes and the TCEH toggle notes for the interest due on May 1, 2009.

Most of our large customers, suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions. As our (or an applicable subsidiary’s) credit ratings decline, the costs to operate our 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 us.

Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets and/or during times when there are significant changes in commodity prices. The inability to access liquidity, particularly on favorable terms, could materially adversely affect results of operations and/or financial condition.

Our businesses are capital intensive. We and our 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 our ability to sustain and grow our businesses and would likely increase capital costs. Our 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 or general U.S. markets;

• changes in interest rates;

• a deterioration of our credit or the credit of our subsidiaries or a reduction in our or our applicable subsidiaries’ credit ratings;

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

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

• a material breakdown in our risk management procedures, and

• the occurrence of changes in our businesses that restrict our ability to access liquidity facilities.

Although we expect 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 our being required to provide cash or letter of credit collateral in substantial amounts. Any perceived reduction in our credit quality could result in clearing agents or other counterparties requesting additional collateral. We have potential credit concentration risk related to the limited number of lenders that provide us liquidity to support our hedging program. A deterioration of the credit quality of such lenders could materially affect our ability to continue such program on acceptable terms.

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

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

Further, a lack of available liquidity could adversely impact the evaluation of our creditworthiness by counterparties and rating agencies. In particular, such concerns by existing and potential counterparties could significantly limit TCEH’s wholesale markets activities, including its long-term hedging program.

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

We provide pension benefits based on either a traditional defined benefit formula or a cash balance formula and also provide certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from EFH Corp. Our costs of providing such benefits and related funding requirements are dependent upon numerous factors, assumptions and estimates and are subject to changes in such factors, assumptions and estimates, including the market value of the assets funding our pension plan and our other postretirement employee benefits (OPEB) plans. 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.

The recent substantial dislocation in the financial markets has caused the value of the investments that fund our pension and OPEB plans to significantly differ from, and may alter the values and actuarial assumptions we use to calculate, our projected future pension plan expense and OPEB costs. A continuation or further decline in the value of these investments could increase the expenses of our pension plan and the costs of our OPEB plan and related funding requirements in the future. Our costs of providing such benefits and related funding requirements are also subject to changing employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.

Goodwill and/or other intangible assets not subject to amortization that we have recorded in connection with the Merger are subject to mandatory annual impairment evaluations and as a result, we could be required to write off some or all of this goodwill and other intangible assets, which may reflect adverse impacts on our 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 our reported results of operations and financial position in future periods.

The loss of the services of our key management and personnel could adversely affect our ability to operate our businesses.

Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete for such personnel with many other companies, in and outside our industry, government entities and

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other organizations. We may not be successful in retaining current personnel or in hiring or retaining qualified personnel in the future. Our failure to attract new personnel or retain existing personnel could have a material adverse effect on our businesses.

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

The Sponsor Group indirectly owns approximately 60% of our 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 our operations, plans, strategies, finances and structure, including whether to enter into any corporate transaction and will have the ability to prevent any transaction that requires the approval of our stockholders.

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

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FORWARD-LOOKING STATEMENTS

This prospectus contains “forward-looking statements.” All statements, other than statements of historical facts, that are included in this prospectus that address activities, events or developments that we expect or anticipate to occur in the future, including such matters as projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power production assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as “will likely result”, “are expected to”, “will continue”, “is anticipated”, “estimated”, “projection”, “target”, and “outlook”), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors under “Risk Factors” and the following important factors, among others, that could cause our actual results to differ materially from those projected in such forward-looking statements:

• prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the U.S. Congress, FERC, the PUCT, the RRC, the NRC, the EPA and the TCEQ, with respect to, among other things:

• allowed prices;

• allowed rates of return;

• industry, market and rate structure;

• purchased power and recovery of investments;

• operations of nuclear generating facilities;

• operations of mines;

• acquisitions and disposal of assets and facilities;

• development, construction and operation of facilities;

• decommissioning costs;

• present or prospective wholesale and retail competition;

• changes in tax laws and policies, and

• changes in and compliance with environmental and safety laws and policies, including climate change initiatives;

• legal and administrative proceedings and settlements;

• general industry trends;

• our ability to attract and retain profitable customers;

• our ability to profitably serve our customers;

• restrictions on competitive retail pricing;

• changes in wholesale electricity prices or energy commodity prices;

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

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

• our ability to effectively hedge against changes in commodity prices, market heat rates and interest rates;

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

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

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

• access to adequate transmission facilities to meet changing demands;

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

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

• commercial bank market and capital market conditions;

• competition for new energy development and other business opportunities;

• the impact of recent economic conditions on our customers;

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

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

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

• changes in assumptions used to estimate costs of providing employee benefits, including pension and OPEB benefits, and future funding requirements related thereto;

• significant changes in critical accounting policies;

• actions by credit rating agencies;

• our ability to implement cost reduction initiatives, and

• with respect to our lignite coal-fueled generation construction and development program, more specifically, our ability to fund such investments, changes in competitive market rules, unexpected judicial rulings, changes in environmental laws or regulations, changes in electric generation and emissions control technologies, changes in projected demand for electricity, our ability and the ability of our 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 our ability to manage the significant construction, commissioning and start-up program to a timely conclusion with limited cost overruns.

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

INDUSTRY AND MARKET INFORMATION

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

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THE TRANSACTIONS

The Merger

On October 10, 2007, Merger Sub, Texas Holdings’ wholly owned subsidiary, acquired EFH Corp. through a merger of Merger Sub with and into EFH Corp. under the terms and conditions of the Merger Agreement. Upon the effectiveness of the Merger, each share of EFH Corp. common stock outstanding immediately prior to the Merger (other than shares held by us or any of our subsidiaries or Texas Holdings or any of its subsidiaries, including Merger Sub, in each case not held on behalf of third parties, or shares held by holders who properly exercised their rights of dissent and appraisal under Texas law) was cancelled and converted into the right to receive $69.25 in cash, without interest and less any applicable withholding taxes.

Equity Contributions

At the closing of the Merger, Texas Holdings received an aggregate equity investment of approximately $8.3 billion. Investment funds affiliated with the Sponsor Group, or their respective assignees, contributed approximately $5.1 billion to Texas Holdings. The Sponsor Group obtained approximately $2.3 billion in equity investments from other existing investors in KKR’s and TPG’s private equity funds and other third party investors. Following the closing of the Merger, the Sponsor Group owned approximately 62% of the limited partnership units issued by Texas Holdings in connection with the Merger.

Debt Financing

In connection with the Merger, in addition to the Equity Contributions described above, we entered into the EFH Senior Interim Facility and TCEH entered into the TCEH Senior Secured Facilities and the TCEH Senior Interim Facility, in each case, arranged by a consortium of arrangers and bookrunners (the “Arranger Group”). For a description of the material terms of each component of the Debt Financing, see Note 17 to the 2007 year-end Financial Statements and Note 7 to the September 30, 2008 Financial Statements.

Also, in connection with the Merger, the Receivables Program was amended, and the special purpose entities established by the third party financial institutions that participate in the Receivables Program requested that Oncor repurchase the receivables that it had previously sold under the Receivables Program. Finally, Oncor also entered into the Oncor Revolving Credit Facility with the Arranger Group.

EFH Senior Interim Facility

The borrowings under the $4.5 billion EFH Senior Interim Facility were used to finance the Merger and related transactions. The proceeds from the offering of the outstanding notes, along with cash on hand, were used by EFH Corp. to repay in full the EFH Senior Interim Facility.

TCEH Senior Secured Facilities

The TCEH Senior Secured Facilities are comprised of:

(i) the $16.45 billion TCEH Initial Term Loan Facility;

(ii) the $4.1 billion TCEH Delayed Draw Term Loan Facility;

(iii) the $1.25 billion TCEH Letter of Credit Facility;

(iv) the $2.7 billion TCEH Revolving Credit Facility, under which amounts are available (A) in the form of letters of credit and (B) for borrowings on same-day notice, referred to as the swingline loans; and

(v) the TCEH Commodity Collateral Posting Facility, the size of which is determined by the out-of-the-money mark-to-market exposure, inclusive of any unpaid settlement amounts, of TCEH and its subsidiaries on a hypothetical portfolio of certain commodity swaps and futures transactions.

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The TCEH Senior Secured Facilities are guaranteed by EFC Holdings and subsidiaries of TCEH. The TCEH Initial Term Loan Facility was used to finance the Merger and related transactions. The TCEH Delayed Draw Term Loan Facility is being used to fund capital expenditures and expenses related to the development of the three new lignite-fueled generation units and the environmental retrofit program. The letters of credit under the TCEH Letter of Credit Facility are being used for general corporate purposes. Borrowings under the TCEH Revolving Credit Facility are being used for working capital and for other general corporate purposes. The proceeds of drawings under the TCEH Commodity Collateral Posting Facility are being used to fund margin payments due on specified volumes of natural gas hedges.

TCEH Senior Interim Facility

The borrowings under the $6.75 billion TCEH Senior Interim Facility were used to finance the Merger and related transactions. The proceeds from the offering of TCEH Notes, along with cash on hand, were used by TCEH to repay in full the TCEH Senior Interim Facility.

Receivables Program

The Receivables Program, a commercial paper-backed accounts receivables securitization program, was amended in connection with the Merger. 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. Subsequent to the Merger, only subsidiaries of TCEH have participated in the accounts receivables securitization program.

Oncor Revolving Credit Facility

The Oncor Revolving Credit Facility is comprised of a senior revolving credit facility in an aggregate principal amount of up to $2.0 billion, of which borrowings are available (a) for borrowings on one or three business days notice, (b) for borrowings of up to $100 million on same-day notice, referred to as the swingline loans and (c) in the form of letters of credit. In addition, subject to the satisfaction of certain conditions, Oncor may increase the commitments under the Oncor Revolving Credit Facility in an amount up to $500 million. The proceeds of borrowings and letters of credit under the Oncor Revolving Credit Facility are being used by Oncor for working capital and for other general corporate purposes.

In May 2008, Oncor secured the Oncor Revolving Credit Facility with a first priority lien on certain of its transmission and distribution assets. Oncor also secured all of its existing long-term debt securities (excluding the transition bonds) with the same lien in accordance with the terms of those securities. The lien contains customary provisions allowing Oncor to use the assets in its business, as well as to replace and/or release collateral as long as the market value of the aggregate collateral is at least 115% of the aggregate secured debt. The lien may be terminated at Oncor’s option upon the termination of the Oncor Revolving Credit Facility.

Ring-Fencing

Upon the consummation of the Merger, EFH Corp. and Oncor implemented several measures that are referred to as “ring-fencing.” Such measures included the following:

• the transfer of EFH Corp.’s ownership of Oncor to Oncor Holdings, a newly-formed special purpose, bankruptcy remote subsidiary, and immediately thereafter the transfer of EFH Corp.’s ownership of Oncor Holdings to a newly-formed, wholly owned subsidiary, Intermediate Holding;

• the conversion of Oncor from a Texas corporation to a Delaware limited liability company;

• the inclusion of covenants in Oncor Holdings’ and Oncor’s limited liability company agreements intended to enhance the separation of Oncor Holdings and its subsidiaries, including Oncor, from Texas Holdings and its other subsidiaries, including Intermediate Holding;

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• the establishment of boards of directors for Oncor Holdings and Oncor with a majority of members who meet the New York Stock Exchange requirements for independence in all material respects and whose unanimous consent is required to take certain material actions, including (i) to consolidate or merge (A) with EFH Corp. or any of EFH Corp.’s other subsidiaries or (B) with any other entity, if Oncor Holdings or Oncor, as applicable, would not be the surviving entity; (ii) to sell, transfer or dispose of all or substantially all of the assets of Oncor Holdings or Oncor, as applicable, without adequate provision for the payment of all of such entity’s creditors; (iii) to institute, or consent to the institution of, bankruptcy or insolvency proceedings in respect of Oncor Holdings or Oncor, as applicable; or (iv) to the fullest extent permitted by law, to dissolve or liquidate Oncor Holdings or Oncor, as applicable, without adequate provision for the payment of all of such entity’s creditors;

• the specific delegation to each of the board of directors and the independent directors of Oncor, each acting by majority vote, of the right to prevent distributions, if it or they determine that it is in the best interests of Oncor to retain such amounts to meet expected future requirements;

• after the appointment of the initial independent directors, the delegation of the ability to nominate, appoint, and fill vacancies in respect of the independent directors of Oncor and Oncor Holdings to a standing nominating committee of Oncor Holdings’ board, a majority of whose members are independent directors; and

• the incurrence of new indebtedness, evidenced by the Oncor Revolving Credit Facility, the lenders of which will be specifically relying on the separateness of Oncor Holdings and Oncor, and their assets, from Texas Holdings and its other subsidiaries.

The ring-fencing measures are based on certain principles articulated by rating agencies and certain commitments made by Texas Holdings and Oncor to the PUCT and the FERC intended to further separate Oncor from Texas Holdings and its subsidiaries and to mitigate Oncor’s credit exposure to those entities and to reduce the risk that the assets and liabilities of Oncor Holdings or of any of its subsidiaries would be substantively consolidated with the assets and liabilities of Texas Holdings or of any of its other subsidiaries in the event of a bankruptcy of one or more of those entities. A number of ring-fencing measures put in place were incorporated into a PUCT order that is legally binding on Oncor. See “Regulation and Rates—Matters with the PUCT—Stipulation Approved by the PUCT.”

The Transactions do not provide for new pledges or encumbrances of the assets of Oncor for the benefit of EFH Corp. and its subsidiaries (other than the ring-fenced entities). Oncor did not incur, guarantee or pledge assets in respect of any incremental new debt related to the Transactions. There was neither new debt issued by nor borrowing at Oncor to finance the Transactions. None of the ring-fenced entities will guarantee or otherwise hold out its credit as being available to support the obligations of EFH Corp. or any of its subsidiaries (other than the ring-fenced entities). In addition, lenders under the TCEH Senior Secured Facilities and the holders of the outstanding notes and the TCEH Notes have acknowledged, and the holders of the exchange notes will acknowledge, by acceptance of the exchange notes, the legal separateness of Oncor and its subsidiaries from the borrowers and guarantors under such financing documents. Lenders under the TCEH Senior Secured Facilities and the holders of the outstanding notes and the TCEH Notes also agreed, and the holders of the exchange notes will agree, by acceptance of the exchange notes, that they will not initiate any bankruptcy proceedings against Oncor Holdings or its subsidiaries and that Oncor Holdings and its subsidiaries are entitled to enforce this non-petition covenant. See “Description of the Notes—General.”

Debt Repayment

Pursuant to the terms of the Merger Agreement, we commenced offers to purchase and consent solicitations with respect to the Specified Notes. In connection with the Merger, we have redeemed and repaid an aggregate of approximately $5.5 billion of existing indebtedness of EFH Corp. and its subsidiaries (including the Specified Notes, but excluding indebtedness of Oncor), including debt that became payable upon the consummation of the Merger. See Note 17 to the 2007 year-end Financial Statements.

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USE OF PROCEEDS

We will not receive any cash proceeds from the issuance of the exchange notes pursuant to the exchange offers. In consideration for issuing the exchange notes as contemplated in this prospectus, we will receive in exchange a like principal amount of outstanding notes, the terms of which are identical in all material respects to the exchange notes, except that the exchange notes will not contain terms with respect to transfer restrictions, registration rights and additional interest for failure to observe certain obligations in the registration rights agreement. The outstanding notes surrendered in exchange for the exchange notes will be retired and cancelled and cannot be reissued. Accordingly, the issuance of the exchange notes will not result in any change in our capitalization.

CAPITALIZATION

The following table summarizes our capitalization as of September 30, 2008. This table should be read in conjunction with the information included under the headings “The Transactions,” “Use of Proceeds,” “Energy Future Holdings Corp. and Subsidiaries Unaudited Pro Forma Condensed Statement of Consolidated Income (Loss),” “Energy Future Holdings Corp. Selected Historical Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes.

Debt:
EFH Corp.:
Notes		4,500
Other unsecured debt		1,829
Total EFH Corp. debt		6,329
EFC Holdings:
Secured debt (a)		99
Unsecured debt (b)		9
Total EFC Holdings debt		108
TCEH:
TCEH Senior Secured Facilities		23,569
TCEH Notes		6,750
Other secured debt		285
Other unsecured debt		1,375
Total TCEH debt		31,979
Oncor:
Secured debt		5,385
Debt of other subsidiaries:
Secured debt (c)		102
Total consolidated debt		43,903
Total shareholders’ equity		5,633
Total capitalization	$	49,536

(a) Does not include EFC Holdings’ guarantee of TCEH Senior Secured Facilities.

(b) Does not include EFC Holdings’ guarantee of the notes.

(c) Consists of building financing lease.

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED INCOME (LOSS)

The following unaudited pro forma condensed statement of consolidated income (loss) was derived by applying pro forma adjustments to the historical audited statements of consolidated income (loss) appearing elsewhere in this prospectus.

The unaudited pro forma condensed statement of consolidated income (loss) for the year ended December 31, 2007 gives effect to the Transactions as if the Transactions had occurred on January 1, 2007. The unaudited pro forma condensed statement of consolidated income (loss) is provided for informational purposes only and is not necessarily indicative of what EFH Corp.’s results of operations would have been if the Transactions had occurred on January 1, 2007, or what EFH Corp.’s results of operations will be for any future periods. Assumptions underlying the pro forma adjustments are described in the accompanying notes, which should be read in conjunction with this unaudited pro forma condensed statement of consolidated income (loss) and with the following information:

• unaudited condensed consolidated financial statements and accompanying notes of EFH Corp. as of September 30, 2008 and for the three- and nine-month periods ended September 30, 2008 and 2007 included elsewhere in this prospectus;

• audited consolidated financial statements and accompanying notes of EFH Corp. as of December 31, 2007 and for each of the three years ended December 31, 2007 included elsewhere in this prospectus, and

• “The Transactions”, “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

EFH Corp. accounted for the Merger under purchase accounting in accordance with the provisions of SFAS No. 141. For purposes of the Merger, EFH Corp. is the acquired entity. Accordingly, the historical financial information of EFH Corp. has been adjusted to give effect to the impact of the consideration paid in connection with the Merger. For purposes of developing pro forma adjustments, assumptions were made that historical values of current assets acquired and current liabilities assumed approximate their fair values.

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 estimated fair value of the assets and liabilities of these operations are materially affected by the current rate setting, and any future changes to, the rate structure set by the PUCT.

The impacts and adjustments in this unaudited pro forma condensed statement of consolidated income (loss) are based on events directly related to the Transactions and do not represent projections or forward-looking statements. The unaudited pro forma condensed statement of consolidated income (loss) is for informational purposes only and should not be considered indicative of actual results that would have been achieved had these events actually been consummated on January 1, 2007 and do not purport to indicate results of operations as of any future date or for any future period. Further, the unaudited pro forma condensed statement of consolidated income (loss) does not reflect the impact of restructuring activities, cost savings, management compensation, nonrecurring charges, annual management fees, employee termination costs and other exit costs that may result from or in connection with the Transactions. For example, the unaudited pro forma financial data do not give effect to the $35 million annual management fee to be paid to the Sponsor Group. See “Related Party Transactions.” The unaudited pro forma condensed statement of consolidated income (loss) does not include certain transaction costs that may be expensed versus capitalized as part of the purchase price. The historical results of EFH Corp. and its subsidiaries are not necessarily indicative of the results that may be expected in any future period.

In preparing the unaudited pro forma condensed statement of consolidated income (loss), the primary adjustments to the historical financial statements of EFH Corp. and its subsidiaries were purchase accounting adjustments which include adjustments necessary to (i) allocate the purchase price to the tangible and intangible assets and liabilities of EFH Corp. and its subsidiaries based on their estimated fair values and (ii) adjust for the impacts related to debt and other financing issued and repaid to consummate the Merger.

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED INCOME (LOSS)

(millions of dollars)

	Historical (a)						Pro Forma Adjustments			Pro Forma
	Predecessor			Successor
	January 1, 2007 through October 10, 2007			October 11, 2007 through December 31, 2007						Year Ended December 31, 2007
Operating revenues	$	8,044		$	1,994		$	7	(b)	$	10,045
Fuel, purchased power costs and delivery fees		(2,381	)		(644	)		(205	)(c)		(3,230	)
Net gain (loss) from commodity hedging and trading activities		(554	)		(1,492	)		—			(2,046	)
Operating costs		(1,107	)		(306	)		1			(1,412	)
Depreciation and amortization		(634	)		(415	)		(276	)(d)		(1,325	)
Selling, general and administrative expenses		(691	)		(216	)		—			(907	)
Franchise and revenue-based taxes		(282	)		(93	)		—			(375	)
Other income		69			14			24	(e)		107
Other deductions		(841	)		(61	)		—			(902	)
Interest income		56			24			—			80
Interest expense and related charges		(671	)		(839	)		(2,108	)(f)		(3,618	)
Income (loss) from continuing operations before income taxes		1,008			(2,034	)		(2,557	)		(3,583	)
Income tax (expense) benefit		(309	)		673			895	(g)		1,259
Income (loss) from continuing operations	$	699		$	(1,361	)	$	(1,662	)	$	(2,324	)

See Notes to Unaudited Pro Forma Condensed Statement of Consolidated Income (Loss).

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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO UNAUDITED PRO FORMA CONDENSED STATEMENT OF

CONSOLIDATED INCOME (LOSS)

(a) Historical presentation—The amounts presented are derived from EFH Corp.’s historical audited consolidated statement of income (loss) for the year ended December 31, 2007, included elsewhere in this prospectus.

(b) Operating revenues—Represents pro forma adjustments required to record the amortization related to the fair value of intangible assets and other noncurrent liabilities and deferred credits related to sales contracts or other legal or economic rights. For purposes of this adjustment, amortization was determined based on straight-line method over an estimated useful life of 6 to 31 years. These adjustments increased operating revenues by approximately $7 million for the year ended December 31, 2007. These adjustments are required to be made to the operating revenues line item in the income statement since the activity associated with the underlying contracts or other legal or economic rights have historically been reported as a component of operating revenues.

(c) Fuel, purchased power costs and delivery fees—Represents pro forma adjustments required to record the amortization related to the fair value of intangible assets related to contracts and other legal or economic rights. For purposes of this adjustment, amortization was determined for different categories of intangible assets based on a straight-line method over useful lives ranging from 2 to 30 years. These adjustments increased costs and expenses by approximately $205 million for the year ended December 31, 2007. Of the $205 million, $158 million relates to intangible asset and liability amortization. The amortization consists of $79 million for favorable purchase and sales contracts with a weighted average life of 11 years, and $80 million for emission and renewable energy credits with a weighted average life of 23 years, slightly offset by $1 million for unfavorable purchase and sales contracts with a weighted average life of 11 years. See Note 3 and Note 28 (under Other Noncurrent Liabilities and Deferred Credits) to the 2007 year-end Financial Statements for additional details of these intangible assets and liabilities. These adjustments are required to be made to the fuel, purchased power costs and delivery fees line item in the income statement since the activity associated with the underlying contracts or other legal or economic rights is reported as a component of such costs. Adjustments also include $47 million in additional amortization expense related to nuclear fuel balances included in property, plant and equipment, reflecting a $299 million increase in the valuation of the nuclear fuel amortized over a five-year life based on a straight-line amortization method.

(d) Depreciation and amortization expense—Represents the pro forma adjustment required to adjust property, plant and equipment to record power generation assets and other tangible property at their estimated fair values, as well as to record amortization of the fair value of customer relationship-based intangible assets. For purposes of this adjustment, depreciation and amortization was determined for different categories of property and intangible assets based on a straight-line method over estimated useful lives ranging from 4 to 45 years. These adjustments increased depreciation and amortization expense approximately $276 million for the year ended December 31, 2007, which consists of a $201 million increase in depreciation of property plant and equipment and a $75 million increase in amortization expense. The increase in depreciation expense primarily reflects depreciation on a straight-line basis of an increase of approximately $8 billion in the value of power generation assets with a weighted average useful life of 26 years. Depreciation expense is based on 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 (see Note 1 to the 2007 year-end Financial Statements). The increase in amortization expense reflects amortization on a straight-line basis of the retail customer relationship intangible asset described in Note 3 to the 2007 year-end Financial Statements over the 4 year weighted average life of the asset. Transmission and distribution assets are considered to be at fair value due to the regulatory recovery of these assets based on historical costs; accordingly, there were no increases or decreases to depreciation expense related to the regulated assets of Oncor. An increase or decrease in the fair value of these assets of $500 million would result in an increase or decrease in depreciation and amortization expense of approximately $19 million on an annual basis.

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(e) Other income—Represents the pro forma adjustment required to adjust Oncor’s generation-related regulatory assets, which were not earning a return, to their estimated fair values as discussed in Note 28 to the 2007 year-end Financial Statements under “Regulatory Assets and Liabilities”. For purposes of this adjustment, accretion was determined based on a straight-line method over a recovery period of nine years. This adjustment increased other income by approximately $24 million for the year ended December 31, 2007.

(f) Interest expense—Represents pro forma adjustments related to the increase in interest expense as a result of the borrowings made to finance the Merger, less certain interest expense associated with the debt that was repaid as part of the Merger. In connection with the Merger, approximately $31,482 million of new debt was incurred by EFH Corp. and its subsidiaries, with approximately $5,263 million of existing debt repaid, resulting in a net increase in debt of approximately $26,219 million. This increase in debt significantly increased the overall interest expense for EFH Corp. The estimated increase in interest expense was calculated based on an aggregate assumed weighted-average interest rate of approximately 8.77% for the new debt issued in connection with the Merger, adjusted for the repayment of existing debt. The pro forma interest expense adjustment reflects the effect of interest rate swaps with a notional amount of $15.050 billion related to the senior secured term loans of TCEH as if these swaps were effective January 1, 2007. See the table below for summary of the calculation of the annualized increase in interest expense, which was then prorated to the predecessor 2007 period to calculate the adjustment. Due to the remaining unhedged variable rate long-term debt, as of September 30, 2008, a 1/8 percent change in interest rates would result in an approximate $5 million change in pretax annual interest expense.

Additionally, this adjustment includes interest amounts arising from the fair valuation of the existing debt of EFH Corp. and its subsidiaries that remained outstanding after the Merger. The final determination of the fair value of the debt was based on the prevailing market interest rates as of the Merger and the related adjustment amortized as an increase (in the case of a discount to par value) or a decrease (in the case of a premium to par value) to interest expense over the remaining life of each debt issuance.

Further, this adjustment includes amounts to reduce interest expense for the removal of existing deferred financing costs, as well as the addition of interest expense associated with the estimated deferred financing costs in connection with the Merger.

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	Principal			Interest Rate (a)	Swap Interest Rate (b)	Annualized Interest
Merger-related long-term debt issuances:
TCEH Initial Term Loan Facility maturing October 10, 2014	$	16,450		8.3960	8.0055	$	1,322
TCEH Delayed Draw Term Loan Facility maturing October 10, 2014		2,150		8.3780			180
TCEH Letter of Credit Facility maturing October 10, 2014		1,250		3.6200			45
TCEH Commodity Collateral Posting Facility maturing October 10, 2012		382		4.4730			17
TCEH Fixed Senior Notes due November 1, 2015		3,000		10.2500			308
TCEH Fixed Senior Notes Series B due November 1, 2015		2,000		10.2500			205
TCEH Senior Toggle Notes due November 1, 2016		1,750		10.5000			184
EFH Corp. Fixed Senior Notes maturing October 10, 2014		2,000		10.8750			218
EFH Corp. Fixed Senior Toggle Notes maturing October 10, 2014		2,500		11.2500			282
Total merger-related issuances		31,482		8.7664			2,761
Merger-related retirements:
TCEH credit facilities (c)		(2,055	)	N/A			(117	)
TCEH Floating Senior Notes due September 16, 2008		(1,000	)	6.1940			(62	)
TCEH Fixed Senior Notes due March 15, 2008		(247	)	6.1250			(15	)
TCEH Fixed Senior Notes due March 15, 2013		(995	)	7.0000			(70	)
TCEH fair value swaps (d)		(14	)	N/A			(2	)
EFC Holdings. unamortized discount (d)		(4	)	N/A			(1	)
EFH Corp. Fixed Senior Notes Series O due November 15, 2009		(997	)	4.8000			(48	)
EFH Corp. Floating Convertible Senior Notes due July 15, 2033		(25	)	6.7430			(2	)
EFH Corp. fair value swaps (d)		66		N/A			9
EFH Corp. unamortized discount (d)		8		N/A			1
Consolidated deferred financing costs (d)		—		N/A			(13	)
Total merger-related retirements		(5,263	)				(320	)
Consolidated unamortized fair value discount (d)		(900	)	N/A			129
Consolidated deferred financing costs (d)				N/A			130
Annual increase in interest expense						$	2,700
Pro forma increase in interest expense (e)						$	2,108

(a) Floating rates are as of December 31, 2007 except for TCEH Floating Senior Notes due 2008, which are as of September 30, 2007. Totals are weighted averages.

(b) Represents weighted average rate of $15.050 billion of floating to fixed interest rate swaps described above.

(c) Annualized interest amount based on 2007 Predecessor period amounts due to variability in average rates and balances.

(d) Amortization period assumed to be 7 years.

(e) Pro forma adjustment applied to the 285 days in the Predecessor period (January 1, 2007 through October 10, 2007).

(g) Income tax provision—Represents the pro forma tax effect of the above adjustments based on an estimated statutory rate of approximately 35%.

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ENERGY FUTURE HOLDINGS CORP. SELECTED

HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table sets forth our selected historical consolidated financial data as of and for the periods indicated. The selected financial data as of December 31, 2006 and 2007 and for each of the three years ended December 31, 2005, 2006 and 2007, including the Predecessor period from January 1, 2007 through October 10, 2007 and the Successor period from October 11, 2007 through December 31, 2007, have been derived from our audited historical consolidated financial statements and related notes included elsewhere in this prospectus. The selected financial data as of December 31, 2003, 2004 and 2005 and for the years ended December 31, 2003 and 2004 have been derived from our historical consolidated financial statements that are not included herein. The unaudited selected financial data as of September 30, 2008 and for the nine months ended September 30, 2008 and September 30, 2007 were derived from our unaudited historical condensed consolidated financial statements included elsewhere in this prospectus.

The unaudited financial data presented have been prepared on a basis consistent with our audited consolidated financial statements. In the opinion of management, such unaudited financial data reflect all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of the results for those periods. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period.

The selected historical consolidated financial data set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes thereto appearing elsewhere in this prospectus.

	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
	(millions of dollars, except ratios and per share amounts)
Statement of Income Data:
Operating revenues (a)	$	1,994		$	8,044	$	10,703	$	10,826		$	9,319		$	8,502
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
Dividends declared per share	$	—		$	1.30	$	1.67	$	1.26		$	0.47		$	0.25
Ratio of earnings to fixed charges (b)		—			2.30		5.11		3.80			1.16			1.94
Ratio of earnings to combined fixed charges and preference dividends (b)		—			2.30		5.11		3.74			1.11			1.87

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	Successor			Predecessor
	December 31, 2007			December 31,
				2006			2005			2004			2003
	(millions of dollars, except ratios)
Balance Sheet Data:
Total assets—end of year (c)	$	64,804		$	27,216		$	27,978		$	24,059		$	32,203
Property, plant & equipment—net—end of year	$	28,650		$	18,569		$	17,006		$	16,495		$	16,432
Goodwill and intangible assets	$	27,319		$	729		$	728		$	723		$	929
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	%
Short-term borrowings	$	1,718		$	1,491		$	798		$	210		$	—
Long-term debt due currently	$	513		$	485		$	1,250		$	229		$	678
Embedded interest cost on long-term debt—end of period (f)		9.5	%		6.6	%		6.3	%		6.0	%		6.3	%
Embedded dividend cost on preferred stock of subsidiaries—end of period (g)		—	%		—	%		—	%		4.4	%		9.7	%

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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			2004			2003
	(millions of dollars)
Statement of Cash Flows Data:
Cash flows provided by (used in) operating activities from continuing operations	$	(450	)	$	2,265		$	4,954		$	2,793		$	1,758		$	2,413
Cash flows provided by (used in) financing activities from continuing operations	$	33,865		$	1,394		$	(2,332	)	$	(1,563	)	$	(6,519	)	$	(1,731	)
Cash flows provided by (used in) investing activities from continuing operations	$	(34,563	)	$	(2,283	)	$	(2,664	)	$	(1,038	)	$	4,280		$	(1,400	)
Other Financial Information:
Capital expenditures, including nuclear fuel	$	707		$	2,395		$	2,297		$	1,104		$	999		$	765

(a) The operating revenues shown above reflect the change in classification for commodity hedging and trading activities discussed in Note 1 to the 2007 year-end Financial Statements that resulted in an increase in operating revenues of $1.492 billion and $554 million for the Successor period from October 11 through December 31, 2007 and the Predecessor period from January 1 through October 10, 2007, respectively, a decrease of $153 million for the year ended December 31, 2006, an increase of $164 million and $103 million for the years ended December 31, 2005 and 2004, respectively, and a decrease of $30 million for the year ended December 31, 2003.

(b) 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.

(c) The total assets shown above reflect the change in presentation related to EFH Corp.’s adoption of FIN 39-1 as discussed in Note 1 to the 2007 year-end Financial Statements. Such change in presentation resulted in an increase of $1.020 billion, $1.383 billion, $2.439 billion, $870 million and $919 million in EFH Corp.’s total assets and total liabilities as of December 31, 2007, 2006, 2005, 2004 and 2003, respectively, as compared to amounts previously reported in the EFH Corp. Annual Report on Form 10-K for the year ended December 31, 2007.

(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.

(f) 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.

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

Note:    Results for 2004 are significantly impacted by charges related to EFH Corp.’s comprehensive restructuring plan.

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	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
	(millions of dollars, except ratios and per share amounts)
Statement of Income Data:
Operating revenues (a)	$	9,001		$	7,743
Income (loss) from continuing operations	$	(983	)	$	591
Income from discontinued operations, net of tax effect	$	—		$	24
Net income (loss) available for common stock	$	(983	)	$	615
Dividends declared per share	$	—		$	1.30
Ratio of earnings to fixed charges (b)		—			2.11
Ratio of earnings to combined fixed charges and preference dividends (b)		—			2.11

	Successor
	September 30, 2008
	(millions of dollars, except ratios)
Balance Sheet Data:
Total assets—end of period	$	67,491
Property, plant & equipment—net—end of period	$	29,600
Goodwill and intangible assets	$	26,495
Capitalization—end of period
Long-term debt, less amounts due currently	$	40,867
Preferred stock of subsidiaries (not subject to mandatory redemption) (c)		—
Common stock equity		5,633
Total	$	46,500
Capitalization ratios—end of period
Long-term debt, less amounts due currently		87.9	%
Preferred stock of subsidiaries (c)		—
Common stock equity		12.1
Total		100.0	%
Short-term borrowings	$	2,620
Long-term debt due currently	$	416
Embedded interest cost on long-term debt—end of period (d)		9.5	%

	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
	(millions of dollars)
Statement of Cash Flows Data:
Cash flows provided by operating activities from continuing operations	$	957		$	1,555
Cash flows provided by financing activities from continuing operations	$	3,052		$	1,323
Cash flows used in investing activities from continuing operations	$	(2,374	)	$	(2,285	)
Other Financial Information:
Capital expenditures, including nuclear fuel	$	2,179		$	2,450

(a) The operating revenues shown above reflect the change in classification for commodity hedging and trading activities discussed in Note 1 to the September 30, 2008, Financial Statements that resulted in an increase in operating revenues of $607 million for the nine months ended September 30, 2007.

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(b) Fixed charges and combined fixed charges and preference dividends exceeded earnings by $1.445 billion for the nine months ended September 30, 2008.

(c) Preferred stock outstanding at September 30, 2008 has a stated amount of $51 thousand.

(d) Represents the annual interest using period-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 period.

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, a change in presentation related to EFH Corp.’s adoption of FIN 39-1 and a change in classification to report the results of commodity hedging and trading activities on a separate line in the income statement instead of within operating revenues. (See Note 1 to the September 30, 2008 Financial Statements “Basis of Presentation.”) The consolidated financial statements of the Successor reflect the application of “purchase accounting.”

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.

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

	Predecessor (a)							Successor
	First Quarter			Second Quarter		Third Quarter		Period from October 11, 2007 through December 31, 2007
2007:
Operating revenues	$	2,355		$	2,405	$	2,983	$	1,994
Income (loss) from continuing operations		(497	)		110		979		(1,361	)
Income from discontinued operations, net of tax effect		—			11		13		1
Net income (loss) 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	$	2,348	$	2,680	$	3,392	$	2,283
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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Reconciliation of Previously Reported Quarterly Information—The following tables present changes to previously reported quarterly results, reflecting the change in classification to report the results of commodity hedging and trading activities on a separate line item in the income statement instead of within operating revenues. Income (loss) from continuing operations, income from discontinued operations, and net income (loss) available for common stock were not affected by this change (see Note 1 to the 2007 year-end Financial Statements for additional information).

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

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

	Predecessor
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
2006:
Previously reported operating revenues	$	2,304	$	2,667	$	3,510		$	2,375
Change in classification		44		13		(118	)		(92	)
Operating revenues	$	2,348	$	2,680	$	3,392		$	2,283

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations covers periods prior to and following the consummation of the Merger. The discussion and analysis of historical periods prior to the consummation of the Merger does not reflect the significant impact that the Merger has had and will have on us, including significantly increased leverage and liquidity requirements. You should read the following discussion of our results of operations and financial condition with the “Energy Future Holdings Corp. and Subsidiaries Unaudited Pro Forma Condensed Statement of Consolidated Income (Loss),” “Energy Future Holdings Corp. Selected Historical Consolidated Financial Data” and the audited and unaudited historical consolidated financial statements and related notes included elsewhere in this prospectus. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in the “Risk Factors” section of this prospectus. Actual results may differ materially from those contained in any forward-looking statements.

You also should read the following discussion of our results of operations and financial condition with “Business” for a discussion of certain of our important financial policies and objectives; performance measures and operational factors we use to evaluate our financial condition and operating performance; and our business segments.

References to “EFH Corp.” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” refer to Energy Future Holdings Corp. and/or its subsidiaries, depending on context. See “Glossary” for other defined terms used in this prospectus. All dollar amounts in the tables in the following discussion and analysis are stated in millions of U.S. dollars unless otherwise indicated.

Business

EFH Corp. 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. See Note 1 to the 2007 year-end Financial Statements for discussion of “ring-fencing”.

In connection with the Merger, certain of the subsidiaries of EFH Corp. established for the purpose of developing and constructing new generation facilities became 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 the 2007 year-end Financial Statements and Note 4 to the September 30, 2008 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 became a subsidiary of TCEH.

Operating Segments

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

The Competitive Electric segment includes the activities of TCEH, as described above, as well as equipment salvage and resale activities related to 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, in 2007 certain revenues and costs associated with installation of equipment that will facilitate Oncor’s technology initiatives designed to improve system reliability.

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See Note 27 to the 2007 year-end Financial Statements and Note 14 to the September 30, 2008 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 the Investors and by the debt financings described in Note 17 to the 2007 year-end 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 the 2007 year-end 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 $22.9 billion of goodwill and $10.0 billion in increased or new net tangible and identifiable intangible assets. As of December 31, 2007, EFH Corp. had principal amount of total debt (short-term borrowings and long-term debt, including amounts due currently) of $41.7 billion.

Uncertain Financial Markets—While EFH Corp. believes its cash on hand and cash from operations combined with availability under its existing credit facilities provides sufficient liquidity to fund current obligations, projected working capital requirements and capital spending, there can be no assurance, considering the current uncertainty in financial markets, that counterparties to its credit facilities will perform as expected through the maturity dates and counterparties in the natural gas hedging program will meet their obligations, or that material unexpected changes in financial markets or the economy will not result in liquidity constraints or require increased funding for obligations including its pension plan and OPEB plans. In light of current market conditions, EFH Corp. reviewed the quality of its investments in money market funds and determined there are no indications that these investments should be valued at less than carrying value at September 30, 2008. In addition, EFH Corp.’s long term capital spending, especially Oncor’s proposed construction of transmission lines for the CREZ Transmission Plan discussed in “Regulation and Rates,” will require access to financial markets.

Also see Note 3 to the September 30, 2008 Financial Statements regarding potential impairment of goodwill and Note 5 to the September 30, 2008 Financial Statements regarding a charge related to the filing by Lehman Brothers Holdings Inc. for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code, Note 15 to the September 30, 2008 Financial Statements for discussion of an investment in a money market fund that is being liquidated, and “Liquidity and Capital Resources” (below) for discussion of actions taken in response to the uncertain financial markets.

Long-Term Hedging Program—EFH Corp. has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, subsidiaries of EFH Corp. have entered into market transactions involving natural gas-related financial instruments. As of October 24, 2008, these subsidiaries have effectively sold forward approximately 2.1 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 280,000 GWh at an assumed 7.5 MMBtu/MWh market heat rate) over the period from 2008 to 2014 at average annual sales prices ranging from $7.20 per MMBtu to $8.35 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 2014, 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

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hedged approximately 77% of its expected baseload generation natural gas price exposure for such period (on an average basis for such period). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices. If market heat rates decline in the future, which would indicate a lessening of such correlation, EFH Corp. expects that the cash flows targeted under the long-term hedging program may not be achieved.

Beginning in the second quarter of 2008, EFH Corp. entered into related put and call transactions (referred to as collars), primarily for outer years of the program, that effectively hedge natural gas prices within a range. These transactions represented approximately 5% of the positions in the program at October 24, 2008, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. EFH Corp. expects to employ both collars and, as has been the case, swap transactions for future hedging activity under its long-term hedging program. Under the terms of the collars, if forward natural gas prices are lower than the floor price, unrealized mark-to-market gains related to the hedges would be recognized in net income, and if forward prices are higher than the ceiling price, unrealized mark-to-market losses related to the hedges would be recognized in net income.

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 October 24, 2008, a $1.00/MMBtu change in natural gas prices across the period from 2008 through 2014 would result in the recognition by EFH Corp. of up to approximately $2.1 billion in pretax unrealized mark-to-market gains or losses.

Reported unrealized mark-to-market net gains associated with the long-term hedging program were significant in the three months ended September 30, 2008 ($6.2 billion) due to net decreases in forward natural gas prices. Reported unrealized mark-to-market net gains in the nine months ended September 30, 2008 totaled $133 million. Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains or losses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices and will in this context be viewed as having resulted in an opportunity cost. The cumulative unrealized mark-to-market net losses related to positions in the long-term hedging program totaled $1.8 billion at December 31, 2007, $1.7 billion at September 30, 2008 and $44 million at October 24, 2008. These values can change materially as market conditions change.

As of September 30, 2008, more than 95% of the long-term hedging transactions were secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility—see discussion below under “Liquidity and Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.

Interest Rate Swap Transactions—See discussion in Note 7 to the September 30, 2008 Financial Statements regarding various interest rate swap transactions entered into since the Merger. As of September 30, 2008, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $16.55 billion principal amount of its senior secured debt maturing from 2009 to 2014. Taking into consideration these swap transactions, approximately 12% of EFH Corp.’s total long-term debt portfolio at September 30, 2008 was exposed to variable interest rate risk. In August 2008, swaps in effect at that time were dedesignated as cash flow hedges in accordance with SFAS 133, and subsequent changes in their fair value are

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being marked-to-market in net income (reported in interest expense and related charges). These swaps were dedesignated as a result of the intent to change the variable interest rate terms of the hedged debt (from three-month LIBOR to one-month LIBOR) in connection with the planned execution of interest rate basis swaps to further reduce the fixed borrowing costs. In October 2008, TCEH entered into interest rate swaps that effectively fix the interest rates at between 7.5% and 7.6% on an additional $1 billion principal amount of the TCEH Senior Secured Facilities; these swaps will also be marked-to-market in net income. EFH Corp. may enter into additional interest rate swap transactions from time to time. The cumulative unrealized mark-to-market net losses related to all interest rate swaps totaled $280 million at December 31, 2007 (reported in accumulated other comprehensive income) and $404 million at September 30, 2008 ($431 million of which was reported in accumulated other comprehensive income) due to changes in market interest rates. These fair values can change materially as market conditions change.

Texas Generation Facilities Development—Luminant is developing three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in the state of Texas with a total estimated capacity of approximately 2,200 MW. Agreements have been executed with EPC contractors to engineer and construct the units; design and procurement activities for the three units are essentially complete, and construction is well underway. Air permits for construction of all three units have been obtained. Aggregate cash capital expenditures for these three units are expected to total approximately $3.25 billion including all construction, site preparation and mining development costs, of which approximately $2.6 billion was incurred as of September 30, 2008. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $5.0 billion upon completion of the units. The expected commercial operation dates of the units remain as follows: Sandow in 2009 and Oak Grove’s two units in 2009 and 2010. See discussions in Note 18 to the 2007 year-end Financial Statements under “Litigation—Generation Facilities” and Note 8 to the September 30, 2008 Financial Statements under “Litigation Related to Generation Development” regarding pending litigation related to the new units.

The development program includes up to $500 million for investments in state-of-the-art emissions controls for the three new units. The development program also includes an environmental retrofit program under which Luminant will install additional environmental control systems at its existing lignite/coal-fueled generation facilities. Estimated capital expenditures associated with these additional environmental control systems total approximately $1.0 billion to $1.3 billion. Luminant has not yet completed all 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 discussions in Note 7 to the 2007 year-end Financial Statements and Note 4 to the September 30, 2008 Financial Statements for information on the net charges resulting from the cancellation of development of eight coal-fueled generation facilities in Texas. In September 2008, the TCEQ unanimously approved EFH Corp.’s application to terminate its air permit applications for the eight coal-fueled generation units.

Retail Pricing—TXU Energy is providing price reductions totaling 15% for certain residential customers through December 31, 2008. In addition, TXU Energy committed in 2006 to not increase prices above then current levels through 2009 for qualifying residential customers who remain on certain plans with rates that were then equal to the price-to-beat rate.

Sale of Oncor Minority Interest—On November 5, 2008, Oncor sold a 19.75% minority stake to an investor group to further enhance Oncor’s separation from Texas Holdings, EFH Corp. and EFH Corp.’s other subsidiaries. The investor group is led by certain firms from Canada and Singapore and is not affiliated with any member of the Sponsor Group, Texas Holdings or EFH Corp. The investor group paid $1.254 billion for the minority stake. See Note 16 to the September 30, 2008 Financial Statements for additional information.

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The proceeds (net of closing costs) of $1.253 billion received by Oncor from the issuance of equity to the investor group and the issuance on the same day of equity to certain members of Oncor management were distributed ultimately to EFH Corp. Under the terms of certain financing arrangements of EFH Corp. and TCEH, under certain circumstances, EFH Corp. is required to repay certain outstanding intercompany loans from TCEH with such proceeds. As of November 5, 2008, $837 million of such intercompany loans were outstanding. On November 6, 2008, EFH Corp. repaid the $253 million balance of such loans that related to payments of principal and interest on EFH Corp. debt. Regarding any excess proceeds, EFH Corp. may retain the funds for general corporate purposes, use the funds for repayment of debt, use the funds for certain investments, or contribute the funds to TCEH to be used for the same purposes.

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

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

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

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

Oncor Matters with the PUCT—See the section entitled “Regulation and Rates” included elsewhere in this prospectus.

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.

Environmental Regulatory Matters—See discussion in Note 3 to the September 30, 2008 Financial Statements regarding the invalidation of the EPA’s Clean Air Interstate Rule and the related impairment of intangible assets representing NO_x and SO₂ emission allowances in the third quarter of 2008.

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Nuclear Generation Development—In September 2008, Luminant filed a combined operating license application with the NRC for two new nuclear generation facilities, each with approximately 1,700 MW (gross capacity), at its existing Comanche Peak nuclear generation site. The application was accepted by the NRC for review in December 2008. In connection with the filing of the application, Luminant and Mitsubishi Heavy Industries Ltd. entered into an agreement to form a joint venture to further the development of the two new nuclear generation units using Mitsubishi Heavy Industry Ltd.’s U.S.–Advanced Pressurized Water Reactor technology. EFH Corp. anticipates that closing of the joint venture will occur in the first quarter of 2009.

In September 2008, Luminant filed Part I of its loan guarantee application with the U.S. Department of Energy (DOE) for financing related to the proposed units. Luminant is currently preparing Part II of the application and expects to submit it to the DOE by mid-December 2008.

Cities Aggregation Power Project—In September 2008, Luminant and certain of its affiliates entered into a 24-year agreement to sell electricity to Cities Aggregation Power Project (CAPP), a non-profit organization that makes bulk electricity purchases on behalf of its member cities and local subdivisions. The agreement was contingent upon (i) CAPP successfully issuing bonds to finance a prepayment to Luminant on behalf of participating cities, (ii) adoption of an ordinance by each of the participating cities that, among other things, authorizes the payment of each such participating city’s share of the electricity cost under the agreement and (iii) CAPP entering into back-to-back contracts with the participating cities for 150 MW of electricity. In December 2008, CAPP determined that the contingencies would not be met. Accordingly, CAPP will not purchase any electricity under the agreement.

Key Risks and Challenges

Following is a discussion of key risks and challenges facing management and the initiatives currently underway to manage such challenges. This section should be read in conjunction with “Risk Factors.”

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 EFH Corp.’s 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 and maintaining consistent cash flow levels. With the expiration of the regulatory price-to-beat rate mechanism on January 1, 2007 (see discussion under the section entitled “Regulation and Rates” included elsewhere in this prospectus), TXU Energy has price flexibility in all of its retail markets with the exception of the sales to customers on fixed rate plans.

Considering current and forecasted electricity supply and sales load and wholesale market positions, EFH Corp.’s portfolio position for the remainder of 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.

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EFH Corp.’s approach to managing commodity price risk focuses on the following:

• employing disciplined hedging and risk management strategies through physical and financial energy-related (electricity and natural gas) contracts 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” above, 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 sales prices for which TXU Energy has price flexibility 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 that were expected to settle in 2008, EFH Corp. could have experienced an approximate $170 million reduction in 2008 pretax earnings for every $1.00 per MMBtu reduction in natural gas prices (approximate 13% change in mid-March 2008 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 mid-March 2008 price) for a full year because of a decline in market heat rates, EFH Corp. could have experienced 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-, nuclear-fueled and wind capacity, which could result in lower market heat rates. EFH Corp. expects that decreases in market heat rates would decrease the value of its generation assets because lower market heat rates generally result in lower wholesale electricity prices, and vice versa.

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 or heat rate hedges. 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 through 2007 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

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north Texas, consisted of more than 3 million electricity consumers (measured by meter counts) as of year-end 2007. TXU Energy currently has approximately 2.2 million retail customers 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:

• Introducing competitive pricing initiatives;

• 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 high quality customer service and improving the overall customer experience. In line with this strategy, TXU Energy continues to implement initiatives to improve customer service;

• Establishing itself as one of the most innovative retailers in the Texas market and developing tailored product offerings to meet customer needs by, in part, investing $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

• Focusing on programs targeted to retain the existing highest-value business market customers and recapturing those business customers who have switched REPs, including 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 certain business markets.

Substantial Leverage, Uncertain Financial Markets and Liquidity Risk

EFH Corp.’s substantial leverage, resulting in part from debt incurred to finance the Merger and related transactions, 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. Principal amount of total debt (representing short-term borrowings and long-term debt, including amounts due currently) at September 30, 2008 was $44.8 billion. In 2008, annual interest expense and related charges are expected to total approximately $3.4 billion. Taking into consideration interest-rate swap transactions as of September 30, 2008, approximately 12% of EFH Corp.’s total long-term debt portfolio is exposed to variable interest rate risk. Principal payments on EFH Corp.’s long-term debt in 2008 are expected to total approximately $513 million.

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), commissioning and start-up risks, 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. would be exposed to

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impairment of construction work-in-process assets and project discontinuance costs, including equipment order cancellation penalties (see Note 18 to the 2007 year-end Financial Statements and Note 8 to the September 30, 2008 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 and have been especially volatile in 2008. Sustained high energy prices and/or ongoing price volatility also creates a risk for regulatory and/or legislative intervention with the mechanisms that govern the competitive wholesale and retail markets in ERCOT. EFH Corp. believes that competitive markets result in a broad range of innovative pricing and service alternatives to consumers and ultimately the most efficient use of resources, and 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. In addition, in July 2008, the U.S. Court of Appeals for the DC Circuit (the DC Circuit Court) invalidated the EPA’s Clean Air Interstate Rule (CAIR), which required reductions of SO₂ and NO_x emissions from power generation facilities in 28 states, including Texas, where EFH Corp.’s generation facilities are located. At this time, EFH Corp. cannot predict the outcome of this decision, including whether the DC Circuit Court will grant the EPA’s request for rehearing or revise its decision to allow CAIR to remain in place during any Court-ordered revision of CAIR by the EPA. See Note 3 to the September 30, 2008 Financial Statements for discussion of additional impairment charges recorded as a result of the court decision.

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.

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 two percent.

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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 the 2007 year-end Financial Statements and Note 8 to the September 30, 2008 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 the 2007 year-end Financial Statements and Note 1 to the September 30, 2008 Financial Statements. EFH Corp. follows accounting principles generally accepted in the U.S. 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 the 2007 year-end Financial Statements and Note 12 to the September 30, 2008 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.

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

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all material intangible assets have been identified. See Notes 2 and 3 to the 2007 year-end Financial Statements and Notes 2 and 3 to the September 30, 2008 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 the 2007 year-end 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. 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. Also see discussion below under “Impairment of Long-Lived Assets”.

The purchase price allocation at September 30, 2008 is substantially complete; however, additional analysis with respect to the value of certain assets, contractual arrangements and contingent liabilities could result in a change in the total amount of goodwill and amounts assigned to EFH Corp.’s reporting units. See Note 2 to the 2007 year-end Financial Statements and Note 2 to the September 30, 2008 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 the 2007 year-end Financial Statements and Note 12 to the September 30, 2008 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

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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.

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. In addition, in August 2008, interest rate swap transactions in effect at that time were dedesignated as cash flow hedges in accordance with SFAS 133, and subsequent changes in their fair value are being marked to market in net income. See further discussion of the long-term hedging program and interest rate swap transactions above under “Significant 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.

	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
Amounts recognized in net income (after-tax):
Unrealized net gains (losses) on positions marked-to-market in net income (a)	$	(955	)	$	(492	)	$	(2	)	$	22
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the period (a)		(56	)		(36	)		24			(16	)
Unrealized ineffectiveness net gains (losses) on positions accounted for as cash flow hedges		—			74			141			(24	)
Reversals of previously recognized unrealized net (gains) losses related to cash flow hedge positions settled in the period		—			(15	)		14			7
Total	$	(1,011	)	$	(469	)	$	177		$	(11	)
Amounts recognized in other comprehensive income (after-tax):
Net gains (losses) in fair value of positions accounted for as cash flow hedges (b)	$	(177	)	$	(288	)	$	598		$	(100	)
Net (gains) losses on cash flow hedge positions recognized in net income to offset hedged transactions (b)		—			(89	)		(45	)		130
Total	$	(177	)	$	(377	)	$	553		$	30

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(a) Amounts have been reclassified to include effects of changes in fair values of positions entered into and settled within the period; this change was made in association with the reclassification of commodity hedging and trading activities discussed in Note 1 to the 2007 year-end Financial Statements.

(b) As discussed in Note 1 to the 2007 year-end Financial Statements under “Basis of Presentation”, these amounts have been reclassified to reflect current presentation.

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 $522 million, $477 million, $466 million and $494 million at September 30, 2008, 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 $58 million, $13 million, $46 million, $68 million and $56 million for the nine months ended September 30, 2008, 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.

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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.

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 2007 year-end Financial Statements, EFH Corp. adopted this new standard January 1, 2007. (See Notes 1 and 14 to the 2007 year-end Financial Statements and Note 15 to the September 30, 2008 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. See Note 3 to the 2007 year-end Financial Statements and Note 3 to the September 30, 2008 Financial Statements for additional discussion.

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 the 2007 year-end 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.

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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 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 the 2007 year-end Financial Statements and Note 4 to the September 30, 2008 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.

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. As of December 31, 2007, depreciation expense for the entire generation fleet was 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 the 2007 year-end 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 the 2007 year-end Financial Statements and Note 3 to the September 30, 2008 Financial Statements for additional information.

Regulatory Assets

The financial statements at September 30, 2008, December 31, 2007 and 2006, reflect total regulatory assets of $1.612 billion, $1.593 billion and $2.161 billion, respectively. These amounts include $893 million, $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 the 2007 year-end Financial Statements and Note 15 to the September 30, 2008 Financial Statements.)

Generation-related regulatory assets 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 the 2007 year-end Financial Statements and Note 15 to the September 30, 2008 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.

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Other regulatory assets that EFH Corp. believes are probable of recovery, but are subject to review and possible disallowance in the regulatory rate case filed by Oncor in June 2008 totaled $446 million at December 31, 2007. These amounts consist primarily of employee retirement costs (see Note 22 to the 2007 year-end Financial Statements and Note 11 to the September 30, 2008 Financial Statements) and storm-related service recovery costs. See Note 28 to the 2007 year-end Financial Statements and Note 15 to the September 30, 2008 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 to eligible employees 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.

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

Consistent with SFAS 87, EFH Corp. uses the calculated value method to determine the market-related value of the assets held in its trust. EFH Corp. includes the realized and unrealized gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.

Additional information regarding EFH Corp.’s pension and OPEB costs is provided in Note 22 to the 2007 year-end Financial Statements and Note 11 to the September 30, 2008 Financial Statements. 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

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(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 the 2007 year-end Financial Statements and Note 11 to the September 30, 2008 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.

Results of Operations for the Three and Nine Months Ended September 30, 2008 and 2007

Presentation and Analysis of Results

The accompanying condensed statements of consolidated income (loss) and comprehensive income (loss) are presented for four periods: three and nine months ended September 30, 2008 (Successor) and three and nine months ended September 30, 2007 (Predecessor), which relate to periods after and before the Merger, respectively, and the accompanying condensed statements of consolidated cash flows are presented for the same nine-month periods. While the results of operations of the Predecessor and Successor are not comparable due to the change in basis resulting from the application of purchase accounting for the Merger, the effects of purchase accounting on the results of the Successor are discussed in the comparison of results for the 2008 and 2007 periods.

See Note 1 (under “Basis of Presentation”) to the September 30, 2008 Financial Statements for discussion of a change in classification of results from commodity hedging and trading activities.

All dollar amounts in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (including the tables) are stated in millions of U.S. dollars unless otherwise indicated.

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EFH Corp. Consolidated Financial Results—Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

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 $712 million, or 24%, to $3.695 billion in 2008 as shown in the table below:

	Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007
Competitive Electric segment:
Total retail electricity revenues	$	2,040		$	1,924
Wholesale electricity revenues		1,134			589
Wholesale balancing activities		(44	)		(19	)
Amortization of intangibles (a)		26			—
Other operating revenues		102			78
Total Competitive Electric segment		3,258			2,572
Regulated Delivery segment		728			712
Net intercompany eliminations		(291	)		(301	)
Total consolidated revenues	$	3,695		$	2,983

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

• Operating revenues in the Competitive Electric segment increased $686 million, or 27%, to $3.258 billion. The increase reflects $545 million in higher wholesale electricity revenues, due to higher prices (driven by higher natural gas prices) and volumes, and $116 million in higher retail electricity revenues, reflecting higher average sales prices and increased sales volumes.

• Operating revenues in the Regulated Delivery segment increased $16 million, or 2%, to $728 million driven by higher distribution and transmission tariffs.

• Net intercompany sales eliminations decreased $10 million, reflecting lower sales by Oncor to REP subsidiaries of TCEH, while Oncor’s sales to nonaffiliated REPs increased.

Fuel, purchased power costs and delivery fees increased $749 million, or 85%, to $1.631 billion. The increase was driven by purchased power costs, reflecting increased volumes and the effect of higher natural gas prices on wholesale power prices. The cost of fuel for natural gas-fueled generation assets also increased due to the higher natural gas prices. The increase also reflects $87 million of net expense recorded in the 2008 period representing amortization of the intangible net asset values of environmental credits, coal purchase contracts and power purchase agreements and the stepped-up value of nuclear fuel resulting from purchase accounting. See additional discussion below in the analysis of Competitive Electric segment results of operations.

The $5.583 billion increase in net gain from commodity hedging and trading activities reflects unrealized mark-to-market net gains totaling $6.088 billion in 2008, driven by the effect of a decrease in forward market prices of natural gas on positions in the long-term hedging program, compared to $479 million in net gains in 2007. See discussion above under “Long-Term Hedging Program” and below in the analysis of Competitive Electric segment results of operations.

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Operating costs increased $20 million, or 6%, to $370 million.

• Operating costs in the Competitive Electric segment increased $21 million, or 15%, to $158 million primarily reflecting higher maintenance costs related to the timing and scope of baseload generation facility outages.

• Operating costs in the Regulated Delivery segment decreased $1 million, or less than 1%, to $213 million, reflecting several factors as discussed in the analysis of Regulated Delivery segment results of operations.

Depreciation and amortization increased $222 million to $431 million. The increase includes $170 million of incremental depreciation expense resulting from stepped-up property, plant and equipment values and $15 million in incremental amortization expense largely related to the intangible value of retail customer relationships, both recorded in connection with purchase accounting and substantially all in the Competitive Electric segment. The remaining increase primarily reflects normal additions and replacements of property and replacements of equipment at the lignite/coal-fueled generation plants.

SG&A expenses increased $20 million, or 9%, to $249 million in 2008.

• SG&A expenses in the Competitive Electric segment increased $10 million, or 6%, to $172 million, reflecting increases in several categories in the retail operations.

• SG&A expenses in the Regulated Delivery segment decreased $2 million, or 5%, to $42 million reflecting the absence of $2 million of fees related to the sales of accounts receivable program.

• Corporate and Other SG&A expenses increased $12 million, or 52%, to $35 million due primarily to Sponsor management fees of $9 million.

Other income totaled $14 million in 2008 and $20 million in 2007. The 2008 amount includes $11 million in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting, and the 2007 amount includes $12 million of amortization of a deferred gain on sale of a business that was eliminated in purchase accounting. Other deductions totaled $541 million in 2008 and $10 million in 2007. The 2008 amount includes $499 million in impairment charges related to NOx and SO₂ environmental allowances intangible assets discussed in Note 3 to the September 30, 2008 Financial Statements and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which has filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code. See Note 5 to the September 30, 2008 Financial Statements for details of other income and deductions.

Interest expense and related charges increased $605 million to $831 million in 2008 reflecting $484 million due to higher average borrowings, driven by the Merger-related financings, and $168 million in higher average interest rates, including a $36 million unrealized mark-to-market gain related to interest rate swaps and $18 million of amortization of debt fair value discount resulting from purchase accounting, partially offset by $47 million in increased capitalized interest.

Income tax expense on income from continuing operations totaled $2.001 billion in 2008 and $506 million in 2007. The effective income tax rate was 35.6% in 2008 and 34.1% in 2007. The effective rates reflect the application of EFH Corp.’s statutory tax rate to the unrealized mark-to-market net gains and the impairment of environmental allowances intangible assets in 2008. The increase in the effective tax rate is driven by the effect of a higher lignite depletion benefit in 2007 on a smaller income base and the absence in 2008 of the production deduction due to forecasted net operating losses.

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Income from continuing operations (an after-tax measure) increased $2.638 billion to $3.617 billion in 2008.

• Results in the Competitive Electric segment increased $2.663 billion to $3.611 billion driven by significantly higher unrealized mark-to-market gains on positions in the long-term hedging program, partially offset by higher net interest expense, the impairment of environmental allowances intangible assets and the effects of purchase accounting.

• Earnings in the Regulated Delivery segment increased $15 million to $139 million primarily driven by higher revenues and higher other income, which reflected the effects of purchase accounting.

• Corporate and Other net expenses totaled $133 million in 2008 and $93 million in 2007. The amounts in 2008 and 2007 include recurring interest expense on outstanding debt and notes and advances from subsidiaries, as well as corporate general and administrative expenses. The increase of $40 million reflects (all amounts are after-tax):

• a $40 million increase in net interest expense, driven by issuance of Merger-related debt;

• an $8 million increase in SG&A expense as discussed above, and

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

partially offset by:

• $12 million in financial advisory, legal and other professional fees in 2007 directly related to the Merger.

EFH Corp. Consolidated Financial Results—Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

EFH Corp.’s operating revenues increased $1.258 billion, or 16%, to $9.001 billion in 2008 as shown in the table below:

	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Competitive Electric segment:
Total retail electricity revenues	$	4,961		$	4,828
Wholesale electricity revenues		2,797			1,571
Wholesale balancing activities		(227	)		(11	)
Amortization of intangibles (a)		(15	)		—
Other operating revenues		293			236
Total Competitive Electric segment		7,809			6,624
Regulated Delivery segment		1,969			1,919
Net intercompany eliminations		(777	)		(800	)
Total consolidated revenues	$	9,001		$	7,743

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

• Operating revenues in the Competitive Electric segment increased $1.185 billion, or 18%, to $7.809 billion. The increase in the wholesale business reflected increased prices (due to higher natural gas prices) and higher sales volumes.

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• Operating revenues in the Regulated Delivery segment increased $50 million, or 3%, to $1.969 billion driven by higher distribution and transmission tariffs.

• Net intercompany sales eliminations decreased $23 million, reflecting lower sales by Oncor to REP subsidiaries of TCEH, while Oncor’s sales to nonaffiliated REPs increased.

Fuel, purchased power costs and delivery fees increased $1.581 billion, or 69%, to $3.867 billion. The increase was driven by purchased power costs, reflecting increased volumes and the effect of higher natural gas prices on wholesale power prices. Higher costs also reflect increased utilization of natural gas-fueled generation facilities and the higher cost of fuel for these facilities. The increase also reflects $246 million of net expense recorded in the 2008 period representing amortization of the intangible net asset values of environmental credits, coal purchase contracts and power purchase agreements and the stepped-up value of nuclear fuel resulting from purchase accounting. See additional discussion below in the analysis of Competitive Electric segment results of operations.

The $359 million decrease in net loss from commodity hedging and trading activities reflects unrealized mark-to-market losses totaling $305 million in 2008, driven by the effect of increasing forward market prices of natural gas on positions in the long-term hedging program, compared to $703 million in 2007. See discussion above under “Long-Term Hedging Program” and below in the analysis of Competitive Electric segment results of operations.

Operating costs increased $55 million, or 5%, to $1.120 billion.

• Operating costs in the Competitive Electric segment increased $48 million, or 11%, to $500 million reflecting higher maintenance costs related to the timing and scope of baseload generation facility outages and other factors as discussed in the analysis of the segment’s results of operations.

• Operating costs in the Regulated Delivery segment increased $4 million, or 1%, to $620 million, reflecting several factors as discussed in the analysis of the segment’s results of operations.

Depreciation and amortization increased $605 million to $1.217 billion. The increase includes $502 million of incremental depreciation expense resulting from stepped-up property, plant and equipment values and $43 million in incremental amortization expense largely related to the intangible value of retail customer relationships, both recorded in connection with purchase accounting and substantially all in the Competitive Electric segment. The remaining increase primarily reflects normal additions and replacements of property replacements of equipment at the lignite/coal-fueled generation plants.

SG&A expenses increased $38 million, or 6%, to $712 million in 2008.

• SG&A expenses in the Competitive Electric segment increased $25 million, or 5%, to $499 million driven by several factors as discussed in the analysis of the segment’s results of operations.

• SG&A expenses in the Regulated Delivery segment decreased $10 million, or 7%, to $126 million reflecting lower incentive compensation, the absence of $5 million in fees related to the sale of accounts receivable program and nonrecurring rebranding costs in 2007.

• Corporate and Other SG&A expenses increased $23 million, or 36%, to $87 million due primarily to Sponsor management fees of $26 million.

Other income totaled $43 million in 2008 and $65 million in 2007. The 2008 other income amount includes $33 million in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting, and the 2007 amount includes $35 million of amortization of a deferred gain on sale of a business that was eliminated in purchase accounting. Other deductions totaled $583 million in 2008 and $901 million in 2007. The 2008 amount includes $501 million in impairment charges related to NOx and SO₂ environmental allowances intangible assets discussed in Note 3 to the September 30, 2008 Financial Statements and $26 million in charges to reserve for net receivables (excluding

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termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which has filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code. The 2007 amount includes net charges of $812 million related to the cancelled development of eight coal-fueled generation units. See Note 5 to the September 30, 2008 Financial Statements for details of other income and deductions.

Interest expense and related charges increased $1.861 billion to $2.505 billion in 2008 reflecting $1.397 billion due to higher average borrowings, driven by the Merger-related financings, and $614 million in higher average interest rates, including $54 million of amortization of debt fair value discount resulting from purchase accounting and a $36 million unrealized mark-to-market gain related to interest rate swaps, partially offset by $150 million in increased capitalized interest.

Income tax benefits on pretax losses totaled $462 million in 2008 compared to income tax expense of $212 million on pretax income in 2007. The 2007 amount includes a deferred tax benefit of $51 million related to an amendment of the Texas margin tax by the Texas legislature. Excluding the effect of this 2007 item, the effective income tax rates were 32.0% on a loss in 2008 compared to 32.8% on income in 2007. (The unusual deferred tax benefit in 2007 distorts the comparison; therefore it has been excluded for purposes of a more meaningful discussion.) The effective rates reflect the application of EFH Corp.’s statutory tax to the unrealized mark-to-market net losses in 2007 and 2008 as well as the 2007 impairment charge related to the cancellation of certain generation facility development activities and the impairment of environmental allowances intangible assets in 2008. The decrease in the effective tax rate is driven by the effect of a higher lignite depletion benefit in 2007 on a smaller income base and the absence in 2008 of the production deduction due to forecasted net operating losses. The lower effective rate is also due to the effect of the Texas margin tax, under which interest expense is not deductible.

Results from continuing operations (an after-tax measure) decreased $1.574 billion to a loss of $983 million in 2008.

• Earnings in the Competitive Electric segment decreased $1.471 billion to a loss of $862 million driven by higher net interest expense, the impairment of environmental allowances intangible assets and the effects of purchase accounting, partially offset by the effect of the 2007 impairment charge related to the cancellation of certain generation facility development activities and the decrease in net unrealized mark-to-market losses on positions in the long-term hedging program.

• Earnings in the Regulated Delivery segment increased $45 million to $309 million primarily driven by higher revenues and higher other income, which reflects the effects of purchase accounting.

• Corporate and Other net expenses totaled $430 million in 2008 and $282 million in 2007. The amounts in 2008 and 2007 include recurring interest expense on outstanding debt and notes and advances from subsidiaries, as well as corporate general and administrative expenses. The increase of $148 million reflects (all amounts are after-tax):

• a $123 million increase in net interest expense, driven by issuance of Merger-related debt;

• $23 million in lower other income reflecting the absence, due to purchase accounting, of amortization of a gain on the sale of a business;

• a $21 million deferred tax benefit in 2007 related to the Texas margin tax;

• a $15 million increase in SG&A expense as discussed above, and

• $8 million in higher depreciation and amortization, primarily due to purchase accounting adjustments,

partially offset by:

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

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

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Competitive Electric Segment Financial Results

	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Operating revenues	$	3,258		$	2,572		$	7,809		$	6,624
Fuel, purchased power costs and delivery fees		(1,923	)		(1,184	)		(4,646	)		(3,086	)
Net gain (loss) from commodity hedging and trading activities		6,045			462			(248	)		(607	)
Operating costs		(158	)		(137	)		(500	)		(452	)
Depreciation and amortization		(296	)		(84	)		(827	)		(245	)
Selling, general and administrative expenses		(172	)		(162	)		(499	)		(474	)
Franchise and revenue-based taxes		(26	)		(25	)		(74	)		(78	)
Other income		2			8			8			19
Other deductions		(533	)		17			(559	)		(792	)
Interest income		20			97			46			260
Interest expense and related charges		(605	)		(130	)		(1,824	)		(341	)
Income (loss) before income taxes		5,612			1,434			(1,314	)		828
Income tax (expense) benefit		(2,001	)		(486	)		452			(219	)
Net income (loss)	$	3,611		$	948		$	(862	)	$	609

Competitive Electric Segment—Sales Volume and Customer Count Data

	Successor		Predecessor				Successor		Predecessor
	Three Months Ended September 30, 2008		Three Months Ended September 30, 2007		Change %		Nine Months Ended September 30, 2008		Nine Months Ended September 30, 2007		Change %
Sales volumes:
Retail electricity sales volumes—gigawatt hours (GWh):
Residential	9,098		8,789		3.5		22,153		21,256		4.2
Small business (a)	2,241		2,313		(3.1	)	5,802		5,861		(1.0	)
Large business and other customers	4,038		3,902		3.5		10,951		10,946		—
Total retail electricity	15,377		15,004		2.5		38,906		38,063		2.2
Wholesale electricity sales volumes	12,472		9,938		25.5		35,529		27,914		27.3
Net sales (purchases) of balancing electricity to/from ERCOT	145		(4	)	—		(1,335	)	622		—
Total sales volumes	27,994		24,938		12.3		73,100		66,599		9.8
Average volume (kWh) per retail customer (b):
Residential	4,757		4,764		(0.1	)	11,654		11,399		2.2
Small business	8,732		8,969		(2.6	)	22,578		22,421		0.7
Large business and other customers	145,802		109,115		33.6		361,554		276,764		30.6
Weather (service territory average)—percent of normal (c):
Percent of normal:
Cooling degree days	100.7	%	97.2	%			109.0	%	94.2	%
Heating degree days	—		—				93.7	%	106.2	%
Customer counts:
Retail electricity customers (end of period and in thousands) (d):
Residential							1,927		1,858		3.7
Small business (a)							258		256		0.8
Large business and other customers							27		35		(22.9	)
Total retail electricity customers							2,212		2,149		2.9

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

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

(c) 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 U.S. Department of Commerce).

(d) Based on number of meters.

Competitive Electric Segment—Revenue and Market Share Data

	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Operating revenues:
Retail electricity revenues:
Residential	$	1,258		$	1,221		$	2,966		$	2,954
Small business (a)		335			335			852			849
Large business and other customers		447			368			1,143			1,025
Total retail electricity revenues		2,040			1,924			4,961			4,828
Wholesale electricity revenues		1,134			589			2,797			1,571
Net sales (purchases) of balancing electricity to/from ERCOT		(44	)		(19	)		(227	)		(11	)
Amortization of intangibles (b)		26			—			(15	)		—
Other operating revenues		102			78			293			236
Total operating revenues	$	3,258		$	2,572		$	7,809		$	6,624
Commodity hedging and trading activities:
Unrealized net gains (losses), including cash flow hedge ineffectiveness	$	6,068		$	479		$	(237	)	$	(695	)
Unrealized net gains (losses) representing reversals of previously recognized fair values of positions settled in the current period		20			—			(68	)		(8	)
Realized net gains (losses) on settled positions (c)		(43	)		(17	)		57			96
Net gain (loss)	$	6,045		$	462		$	(248	)	$	(607	)
Average revenues per MWh:
Residential	$	138.32		$	138.96		$	133.90		$	138.99
Estimated share of ERCOT retail markets (d) (e) (f):
Residential								37	%		36	%
Business markets								26	%		27	%

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

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

(c) Includes physical commodity trading activity not subject to mark-to-market accounting of $11 million and $7 million in net losses in the three months ended September 30, 2008 and 2007, respectively, and $29 and $13 million in net losses in the nine months ended September 30, 2008 and 2007, respectively.

(d) Based on number of meters at end of period.

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

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

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Competitive Electric Segment—Production, Purchased Power and Delivery Cost Data

	Successor		Predecessor		Successor		Predecessor
	Three Months Ended September 30, 2008		Three Months Ended September 30, 2007		Nine Months Ended September 30, 2008		Nine Months Ended September 30, 2007
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear	$	25	$	24	$	69	$	63
Lignite/coal		172		161		485		451
Total baseload fuel		197		185		554		514
Natural gas fuel and purchased power		1,161		559		2,532		1,377
Amortization of intangibles (a)		87		—		246		—
Other costs		94		57		304		203
Fuel and purchased power costs		1,539		801		3,636		2,094
Delivery fees (b)		384		383		1,010		992
Total	$	1,923	$	1,184	$	4,646	$	3,086
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	4.88	$	4.68	$	4.75	$	4.59
Lignite/coal (c)	$	15.39	$	14.18	$	15.83	$	14.31
Natural gas fuel and purchased power	$	104.02	$	63.71	$	91.55	$	62.29
Delivery fees per MWh	$	24.77	$	25.09	$	25.69	$	25.60

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

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

(c) 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.

	Successor		Predecessor				Successor		Predecessor
	Three Months Ended September 30, 2008		Three Months Ended September 30, 2007		Change %		Nine Months Ended September 30, 2008		Nine Months Ended September 30, 2007		Change %
Production and purchased power volumes (GWh):
Nuclear	4,996		5,110		(2.2	)	14,448		13,664		5.7
Lignite/coal	12,240		12,353		(0.9	)	33,697		34,297		(1.7	)
Total baseload generation	17,236		17,463		(1.3	)	48,145		47,961		0.4
Natural gas-fueled generation	2,124		2,108		0.8		3,843		3,491		10.1
Purchased power	9,042		6,662		35.7		23,816		18,619		27.9
Total energy supply	28,402		26,233		8.3		75,804		70,071		8.2
Less line loss and power imbalances	408		1,295		(68.5	)	2,704		3,472		(22.1	)
Net energy supply volumes	27,994		24,938		12.3		73,100		66,599		9.8
Baseload capacity factors (%):
Nuclear	98.4	%	100.6	%	(2.2	)	95.6	%	90.8	%	5.3
Lignite/coal	95.0	%	95.8	%	(0.8	)	87.7	%	89.7	%	(2.2	)
Total baseload generation	95.5	%	97.2	%	(1.7	)	89.8	%	90.0	%	(0.2	)

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Competitive Electric Segment Financial Results—Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

	Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007
Total retail electricity revenues	$	2,040		$	1,924
Wholesale electricity revenues		1,134			589
Wholesale balancing activities		(44	)		(19	)
Amortization of intangibles (a)		26			—
Other operating revenues		102			78
Total operating revenues	$	3,258		$	2,572

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

Operating revenues increased $686 million, or 27%, to $3.258 billion in 2008, as shown in the table above.

The $116 million, or 6%, increase in retail electricity revenues reflected the following:

• Higher average pricing contributed $68 million to the revenue increase. Higher average retail pricing reflected higher prices in the business markets driven by higher natural gas prices, partially offset by an approximate $5 million effect of lower pricing in the residential customer market. Lower residential pricing reflected the effect of a five percent price discount in October 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.

• A two percent increase in retail sales volumes contributed $48 million to the revenue increase. Residential volumes increased four percent, primarily due to an increase in residential customer counts and the effects of slightly warmer weather in 2008 compared to 2007. Business and other customer volumes increased 1%.

• Total retail electricity customer counts at September 30, 2008 increased three percent from September 30, 2007. Competitive activity resulted in a four percent increase in residential customers and a one percent increase in small business customers.

Wholesale electricity revenues increased $545 million, or 93%. A 53% increase in average wholesale electricity prices, driven by higher natural gas prices, contributed $395 million to revenue growth, and a 25% increase in sales volumes contributed $150 million. Higher wholesale sales and purchase volumes reflected several factors, including increased demand (due to warmer weather) and congestion, as well as increased near-term bilateral power contracting activity due in part to increased demand and market volatility in 2008. The higher natural gas prices also contributed to the increase in fuel and purchased power costs.

Wholesale sales and purchases of electricity are reported gross in the income statement only if the transactions are scheduled for physical delivery with ERCOT. In ERCOT’s grid management activities, all scheduled transactions may not result in physical delivery, but EFH Corp. has no visibility into those activities.

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

Other operating revenues increased $24 million, or 31%, to $102 million primarily due to higher retail natural gas revenues reflecting increased prices.

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Fuel, purchased power costs and delivery fees increased $739 million, or 62%, to $1.923 billion. The increase was driven by higher purchased power costs, reflecting 36% growth in purchased power volumes as well as the effect of higher natural gas prices on wholesale power prices. The increase also reflected a 53% increase in fuel costs per MWh in natural gas-fueled generation facilities due to the higher natural gas prices. Higher fuel costs also reflected higher usage and prices (including transportation costs) of purchased coal. The increase reflects $87 million of net expense recorded in the 2008 period representing amortization of the intangible net asset values of environmental credits, coal purchase contracts and power purchase agreements and the stepped-up value of nuclear fuel resulting from purchase accounting. Other cost increases included $37 million related primarily to congestion-related charges and $14 million in higher cost of natural gas for resale.

Results from commodity hedging and trading activities include realized and unrealized gains and losses associated with financial instruments used for commodity hedging and trading purposes, as well as gains and losses on physical sales and purchases of commodities for trading and certain commodity hedging purposes. A substantial majority of the commodity hedging activities are intended to mitigate the risk of commodity price movements on future revenues and involve natural gas positions entered into as part of the long-term hedging program. The results of these activities have been volatile because of the effects of movements in forward natural gas prices on unrealized mark-to-market valuations. Following is an analysis of activities for the three months ended September 30, 2008 and 2007:

Three Months Ended September 30, 2008—Unrealized mark-to-market net gains totaling $6.088 billion include:

• $6.091 billion in net gains related to hedge positions, which includes $6.074 billion in net gains from changes in fair value and $17 million in net gains that represent reversals of previously recorded fair values of positions settled in the period. These net gains are driven by the effect of decreases in natural gas prices in forward periods on positions in the long-term hedging program;

• $10 million in “day one” losses related to large hedge positions (see Note 10 to the September 30, 2008 Financial Statements), and

• $7 million in net gains related to trading positions, which includes $4 million in net gains from changes in fair value and $3 million in net gains that represent reversals of previously recorded fair values of positions settled in the period.

Realized net losses totaling $43 million include:

• $105 million in net losses related to hedge positions that primarily offset hedged electricity revenues recognized in the period, and

• $62 million in net gains related to trading positions.

Three Months Ended September 30, 2007—Unrealized mark-to-market net gains totaling $479 million include:

• $539 million in net gains related to hedge positions, which includes $542 million in net gains from changes in fair value and $3 million in net losses that represent reversals of previously recorded fair values of positions settled in the period, and

• a $58 million “day one” loss on a related series of commodity price hedges (see Note 10 to the September 30, 2008 Financial Statements).

Realized net losses totaling $17 million include:

• $4 million in net losses related to hedge positions that offset hedged electricity revenues recognized in the period, and

• $13 million in net losses related to trading positions.

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Operating costs increased $21 million, or 15%, to $158 million in 2008. The increase reflects $16 million in higher maintenance costs related to the timing and scope of planned and unplanned outages in baseload generation facilities, $4 million in costs related to combustion turbines now being operated for TCEH’s own benefit, $4 million in higher property taxes and $4 million of expenses associated with operational readiness at the generation units under construction, partially offset by $7 million in costs in 2007 for utilization of SO₂ credits for the lignite/coal-fueled generation plants.

Depreciation and amortization increased $212 million to $296 million. The increase includes $170 million of incremental depreciation expense from stepped-up property, plant and equipment values and $13 million in incremental amortization expense related to the intangible value of customer relationships, each resulting from the effects of purchase accounting. The remaining increase primarily reflects normal additions and replacements of equipment in generation operations.

SG&A expenses increased $10 million, or 6%, to $172 million in 2008. The increase reflects:

• $11 million in higher expenses in the retail operations, primarily increased employees and labor costs to support customer growth initiatives and computer system enhancement costs, net of a $1 million decrease in fees associated with the sale of accounts receivable program; and

• $7 million in higher retail customer bad debt expense,

partially offset by lower administrative costs related to generation facility development activities, reflecting the 2007 cancellation of certain coal-fueled generation projects.

Other income totaled $2 million in 2008 and $8 million in 2007. Other deductions totaled $533 million in 2008 and a net credit of $17 million in 2007. The 2008 amount includes $499 million in impairment charges related to NOx and SO₂ environmental allowances intangible assets discussed in Note 3 to the September 30, 2008 Financial Statements and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which has filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code. The 2007 amount includes a $48 million reduction in the liability previously recorded for leases related to gas-fueled combustion turbines that EFH Corp. had ceased operating for its own benefit, charges of $17 million in connection with the cancellation of the development of eight coal-fueled generation units and a $10 million charge related to the termination of a railcar operating lease.

Interest income decreased $77 million to $20 million in 2008 reflecting lower average borrowings.

Interest expense and related charges increased by $475 million to $605 million in 2008. The increase reflects $621 million due to higher average borrowings, driven by the Merger-related financings, partially offset by $99 million in lower average interest rates, including a $36 million unrealized mark-to-market gain related to interest rate swaps and $4 million of amortization of debt fair value discount resulting from purchase accounting, and $47 million in increased capitalized interest.

Income tax expense totaled $2.001 billion in 2008 and $486 million in 2007. The effective income tax rate was 35.7% in 2008 and 33.9% in 2007. The effective rates reflect the application of EFH Corp.’s statutory tax rate to the unrealized mark-to-market net gains and the impairment of environmental allowances intangible assets in 2008. The increase in the effective tax rate is driven by the effect of a higher lignite depletion benefit in 2007 on a smaller income base and the absence in 2008 of the production deduction due to forecasted net operating losses.

Net income increased $2.663 billion to $3.611 billion in 2008 driven by unrealized mark-to-market gains on positions in the long-term hedging program, partially offset by higher net interest expense, the impairment of environmental allowances intangible assets and the effects of purchase accounting.

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Competitive Electric Segment Financial Results—Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Total retail electricity revenues	$	4,961		$	4,828
Wholesale electricity revenues		2,797			1,571
Wholesale balancing activities		(227	)		(11	)
Amortization of intangibles (a)		(15	)		—
Other operating revenues		293			236
Total operating revenues	$	7,809		$	6,624

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

Operating revenues increased $1.185 billion, or 18%, to $7.809 billion in 2008, as shown in the table above.

The $133 million, or 3%, increase in retail electricity revenues reflected the following:

• A two percent increase in retail sales volumes contributed $107 million to the revenue increase. Residential volumes increased four percent reflecting the effects of warmer than normal weather in 2008 combined with the cooler than normal weather experienced in 2007 and an increase in residential customer counts as discussed in the analysis of third quarter results. Business and other customer volumes were comparable with 2007.

• Higher average pricing increased revenues by $26 million. Higher average retail pricing reflected higher prices in the business markets driven by higher natural gas prices, partially offset by an approximate $108 million effect of lower pricing in the residential customer market. Lower residential pricing reflected the effect of a six percent price discount in March 2007, an additional four percent price discount in June 2007 and another five percent price discount in October 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.

Wholesale electricity revenues increased $1.226 billion, or 78%. A 40% increase in average wholesale electricity prices driven by higher natural gas prices contributed $797 million to revenue growth and a 27% increase in sales volumes contributed $429 million. The rise in natural gas prices through July 2008 reflected the overall trend of higher energy prices and increased demand in natural gas-fueled generation due to warmer weather in 2008. Higher wholesale sales and purchase volumes reflected several factors, including increased demand (due to warmer weather), baseload plant outages and congestion, as well as increased near-term bilateral power contracting activity due in part to increased demand and market volatility in 2008. The higher natural gas prices also contributed to the increase in fuel and purchased power costs.

Wholesale balancing activity comparisons are not generally meaningful because the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, which are highly variable. The relatively large amount in 2008 reflects weather-driven volatility, generation facility outages and congestion effects.

Other operating revenues increased $57 million, or 24%, to $293 million primarily due to higher retail natural gas revenues reflecting increased prices.

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Fuel, purchased power costs and delivery fees increased $1.560 billion, or 51%, to $4.646 billion. The increase was driven by higher purchased power costs, reflecting 28% growth in purchased power volumes as well as the effect of higher natural gas prices on wholesale power prices. The increase also reflected greater utilization of natural gas-fueled generation facilities to meet peak demand and a 56% increase in fuel costs per MWh in those facilities due to higher natural gas prices. Higher fuel costs also reflected higher usage and prices (including transportation costs) of purchased coal. The increase reflects $246 million of net expense recorded in the 2008 period representing amortization of the intangible net asset values of environmental credits, coal purchase contracts and power purchase agreements and the stepped-up value of nuclear fuel resulting from purchase accounting. Other cost increases included $101 million related primarily to congestion-related charges and $41 million in higher costs of natural gas for resale.

Following is an analysis of results from commodity hedging and trading activities for the nine months ended September 30, 2008 and 2007:

Nine Months Ended September 30, 2008—Unrealized mark-to-market net losses totaling $305 million include:

• $250 million in net losses related to hedge positions, which includes $248 million in net losses from changes in fair value and $2 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;

• $69 million in “day one” net losses related to large hedge positions (see Note 10 to the September 30, 2008 Financial Statements), and

• $13 million in net gains related to trading positions, which includes $79 million in net gains from changes in fair value and $66 million in net losses that represent reversals of previously recorded fair values of positions settled in the period.

Realized net gains totaling $57 million include:

• $76 million in net losses related to hedge positions that primarily offset hedged electricity revenues recognized in the period, and

• $133 million in net gains related to trading positions.

Nine Months Ended September 30, 2007—Unrealized mark-to-market net losses totaling $703 million include:

• $557 million in net losses related to hedge positions, which includes $585 million in net losses from changes in fair value and $28 million in net gains that represent reversals of previously recorded fair values of positions settled in the period;

• $218 million in “day one” losses related to large hedge positions and a $30 million “day one” gain on a long-term power purchase agreement (see Note 10 to the September 30, 2008 Financial Statements);

• $92 million in hedge ineffectiveness net gains, which includes $111 million in net gains from changes in fair value and $19 million in net losses that represent reversals of previously recorded unrealized net gains related to positions settled in the period. These amounts relate to positions accounted for as cash flow hedges, and

• $46 million in net losses related to trading positions, which includes $29 million in net losses from changes in fair value and $17 million in net losses that represent reversals of previously recorded fair values of positions settled in the period.

Realized net gains totaling $96 million include:

• $70 million in net gains related to hedge positions that offset hedged electricity revenues recognized in the period, and

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• $26 million in net gains related to trading positions.

Operating costs increased $48 million, or 11%, to $500 million in 2008. The increase reflects $36 million in higher maintenance costs related to the timing and scope of planned and unplanned outages in baseload generation facilities, $11 million in costs related to combustion turbines now being operated for TCEH’s own benefit, $10 million in higher property taxes and $5 million of expenses associated with operational readiness at the generation units under construction, partially offset by $7 million in costs in 2007 for utilization of SO₂ credits for the lignite/coal-fueled generation plants and $3 million in individually insignificant items.

Depreciation and amortization increased $582 million to $827 million. The increase includes $502 million of incremental depreciation expense from stepped-up property, plant and equipment values and $38 million in incremental amortization expense related to the intangible value of customer relationships, each resulting from the effects of purchase accounting. The remaining increase primarily reflects normal additions and replacements of equipment in generation operations.

SG&A expenses increased $25 million, or 5%, to $499 million in 2008. The increase reflects:

• $26 million in higher expenses in the retail operations, primarily increased employees and labor costs to support customer growth initiatives and increased marketing and computer systems enhancement costs, net of a $6 million decrease in fees associated with the sale of accounts receivable program, and

• $16 million in higher retail customer bad debt expense,

partially offset by lower administrative costs related to generation facility development activities, reflecting the 2007 cancellation of certain coal-fueled generation projects.

Other income totaled $8 million in 2008 and $19 million in 2007. The 2007 amount includes $7 million of royalty income and $6 million in penalties received due to nonperformance under a coal transportation agreement.

Other deductions totaled $559 million in 2008 and $792 million in 2007. The 2008 amount includes $501 million in impairment charges related to NOx and SO₂ environmental allowances intangible assets discussed in Note 3 to the September 30, 2008 Financial Statements and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which has filed for protection under Chapter 11 of the U.S. Bankruptcy Code. The 2007 amount includes net charges of $812 million in connection with the cancellation of the development of eight coal-fueled generation units, a $48 million reduction in the liability previously recorded for leases related to gas-fueled combustion turbines that EFH Corp. had ceased operating for its own benefit and a $10 million charge related to the termination of a railcar operating lease. See Note 5 to the September 30, 2008 Financial Statements for more details.

Interest income decreased $214 million, or 82%, to $46 million in 2008 reflecting lower average borrowings.

Interest expense and related charges increased $1.483 billion to $1.824 billion in 2008. The increase reflects $1.672 billion due to higher average borrowings, driven by the Merger-related financings, partially offset by $150 million in increased capitalized interest and $38 million in lower average interest rates, including a $36 million unrealized mark-to-market gain related to interest rate swaps, and $11 million of amortization of debt fair value discount resulting from purchase accounting.

Income tax benefit on a pretax loss totaled $452 million in 2008 and income tax expense on pretax income totaled $219 million in 2007. The 2007 amount includes a deferred tax benefit of $30 million related to an amendment of the Texas margin tax by the Texas legislature. Excluding the effect of this 2007 item, the effective income tax rates were 34.4% on a loss in 2008 compared to 30.1% on income in 2007. (The unusual deferred tax

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benefit in 2007 distorts the comparison; therefore it has been excluded for purposes of a more meaningful discussion.) The effective rates reflect the application of EFH Corp.’s statutory tax to the unrealized mark-to-market net losses in 2007 and 2008 as well as the 2007 impairment charge related to the cancellation of certain generation facility development activities and the impairment of environmental allowances intangible assets in 2008. The increase in the effective tax rate is driven by the effect of a lower lignite depletion benefit in 2008 on a smaller income base and the absence in 2008 of the production deduction due to forecasted net operating losses. The impact on the rate is also due to the effect of the Texas margin tax on pretax losses in 2008, under which interest expense is not deductible.

Net income (loss) decreased $1.471 billion to a net loss of $862 million in 2008 driven by higher net interest expense, the impairment of environmental allowances intangible assets and the effects of purchase accounting, partially offset by the effect of the 2007 impairment charge in connection with the cancellation of certain generation facility development activities and the decrease in net unrealized mark-to-market losses on positions in the long-term hedging program.

Regulated Delivery Segment Financial Results

	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Operating revenues	$	728		$	712		$	1,969		$	1,919
Operating costs		(213	)		(214	)		(620	)		(616	)
Depreciation and amortization		(128	)		(119	)		(370	)		(353	)
Selling, general and administrative expenses		(42	)		(44	)		(126	)		(136	)
Franchise and revenue-based taxes		(67	)		(69	)		(186	)		(190	)
Other income		12			—			34			3
Other deductions		(3	)		(7	)		(17	)		(26	)
Interest income		12			14			34			42
Interest expense and related charges		(80	)		(79	)		(229	)		(233	)
Income before income taxes		219			194			489			410
Income tax expense		(80	)		(70	)		(180	)		(146	)
Net income	$	139		$	124		$	309		$	264

Regulated Delivery Segment Operating Data

	Successor	Predecessor		Successor	Predecessor
	Three Months Ended September 30, 2008	Three Months Ended September 30, 2007	Change %	Nine Months Ended September 30, 2008	Nine Months Ended September 30, 2007	Change %
Operating statistics—volumes:
Electric energy delivered (GWh)	31,546	31,558	—	84,038	81,523	3.1
Reliability statistics (a):
System Average Interruption Duration Index (SAIDI) (nonstorm)				82.63	79.22	4.3
System Average Interruption Frequency Index (SAIFI) (nonstorm)				1.10	1.14	(3.5	)
Customer Average Interruption Duration Index (CAIDI) (nonstorm)				75.30	69.51	8.3
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters):				3,116	3,087	0.9

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	Successor		Predecessor		Successor		Predecessor
	Three Months Ended September 30, 2008		Three Months Ended September 30, 2007		Nine Months Ended September 30, 2008		Nine Months Ended September 30, 2007
Operating revenues:
Electricity distribution revenues (b):
Affiliated (TCEH)	$	290	$	300	$	773	$	794
Nonaffiliated		355		331		960		889
Total distribution revenues		645		631		1,733		1,683
Third-party transmission revenues		72		66		207		192
Other miscellaneous revenues		11		15		29		44
Total operating revenues	$	728	$	712	$	1,969	$	1,919

(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 twelve months ended September 30, 2008 and 2007 data.

(b) Includes transition charge revenue associated with the issuance of securitization bonds totaling $40 million and $42 million for the three months ended September 30, 2008 and 2007, respectively, and $108 million and $112 million for the nine months ended September 30, 2008 and 2007, respectively. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs.

Regulated Delivery Segment Financial Results—Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

Operating revenues increased $16 million, or 2%, to $728 million in 2008. The revenue increase reflected:

• $14 million from increased distribution tariffs to recover transmission costs;

• an estimated $6 million impact of growth in points of delivery;

• $6 million in higher transmission revenues primarily due to rate increases to recover ongoing investment in the transmission system, and

• $4 million in increased miscellaneous revenues including $2 million of accrued pole contact revenues and $2 million of revenues for services provided to REPs and other customers (with a related increase in operating costs),

partially offset by:

• $7 million in lower revenues due to the absence in 2008 of revenues for installation of third party equipment related to Oncor’s technology initiatives;

• an estimated $6 million due to lower average consumption, as the effect of slightly warmer weather was more than offset by declines in usage, and

• $1 million in lower charges to REPs related to transition bonds (with a related decrease in amortization of the related regulatory asset).

Operating costs decreased $1 million, or less than 1%, to $213 million in 2008. The decrease reflected:

• $6 million of lower expenses due to the absence in 2008 of costs for installation of third party equipment related to Oncor’s technology initiatives, and

• $2 million in lower vegetation management expenses,

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partially offset by:

• $6 million in increased labor and benefits costs for restoration of service as a result of weather events, more stringent service requirements, increased services provided to REPs and other customers and equipment installation activities, and

• $2 million in software license and service expenses related to Oncor’s purchase of a BPL based “Smart Grid” network in May 2008.

Depreciation and amortization increased $9 million, or 8%, to $128 million in 2008. The increase reflected $11 million in higher depreciation due to ongoing investments in property, plant and equipment as well as $2 million in lower amortization of the regulatory assets associated with the transition bonds (with a related decrease in revenues).

SG&A expenses decreased $2 million, or 5%, to $42 million in 2008. The decrease reflected:

• $2 million in lower incentive compensation expense;

• $2 million in lower fees due to Oncor’s exit from the sale of accounts receivable program, and

• $2 million in decreased bad debt expense,

partially offset by $3 million in increased employee benefit costs and $2 million in higher professional fees.

Franchise and revenue-based taxes decreased $2 million, or 3%, to $67 million in 2008 reflecting a decrease in state franchise taxes due to the 2007 enactment of the Texas margin tax, which is accounted for as an income tax. Local franchise fees resulting from the 2006 cities rate settlement totaled $3 million and $2 million for the three months ended September 30, 2008 and 2007, respectively.

Other income totaled $12 million in 2008 and zero in 2007. The 2008 amount reflects accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. See “Regulatory Assets and Liabilities” in Note 15 to the September 30, 2008 Financial Statements for additional information.

Other deductions totaled $3 million in 2008 and $7 million in 2007. The 2007 amount included costs associated with the 2006 cities rate settlement totaling $6 million.

Interest income decreased $2 million, or 14%, to $12 million in 2008. The decrease reflects $1 million in lower earnings on assets held for employee benefit plans and a $1 million decrease in reimbursement of transition bond interest from TCEH.

Interest expense increased $1 million, or 1%, to $80 million in 2008. The variance reflected a $6 million effect of higher average borrowings, reflecting the ongoing capital investment in the business, including the purchase of an existing BPL-based “Smart Grid” network, partially offset by a decrease of $5 million due to lower average interest rates driven by increased short-term borrowings prior to the September 2008 issuance of $1.5 billion in senior secured notes (see Note 7 to the September 30, 2008 Financial Statements). The average interest rate effect is net of a $1 million increase due to the amortization of the fair value discount related to transition bonds that was recorded due to purchase accounting.

Income tax expense totaled $80 million in 2008 compared to $70 million in 2007. The effective income tax rate increased to 36.5% in 2008 from 36.1% in 2007. The increased rate is driven by a decrease in the benefit from the Medicare subsidy for post-employment benefits.

Net income increased $15 million, or 12%, to $139 million driven by increased revenues and higher other income, which reflects the effects of purchase accounting.

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Regulated Delivery Segment Financial Results—Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Operating revenues increased $50 million, or 3%, to $1.969 billion in 2008. The revenue increase reflected:

• $32 million from increased distribution tariffs to recover transmission costs;

• an estimated $16 million impact of growth in points of delivery;

• $15 million in higher transmission revenues primarily due to rate increases to recover ongoing investment in the transmission system;

• an estimated $3 million from higher average consumption, as the estimated effect of warmer weather was partially offset by usage declines, and

• $7 million in increased miscellaneous revenues, including $3 million of revenues for services provided to REPs and other customers (with a related increase in operating costs) and $2 million of accrued pole contact revenues,

partially offset by:

• $19 million in lower revenues due to the absence in 2008 of revenues for installation of third party equipment related to Oncor’s technology initiatives, and

• $4 million in lower charges to REPs related to transition bonds (with a related decrease in amortization of the related regulatory asset).

Operating costs increased $4 million, or 1%, to $620 million in 2008. The increase reflected:

• $15 million in increased labor and benefits costs for restoration of service as a result of weather events, more stringent service requirements, increased services provided to REPs and other customers and equipment installation activities;

• $3 million in higher vegetation management expenses, and

• $3 million in software license and service expenses related to Oncor’s purchase of a BPL based “Smart Grid” network in May 2008,

partially offset by $18 million of lower expenses due to the absence in 2008 of costs for installation of third party equipment related to Oncor’s technology initiatives.

Depreciation and amortization increased $17 million, or 5%, to $370 million in 2008. The increase reflected $21 million in higher depreciation due to ongoing investments in property, plant and equipment, partially offset by $4 million in lower amortization of the regulatory assets associated with the transition bonds (with a related decrease in revenues).

SG&A expenses decreased $10 million, or 7%, to $126 million in 2008. The decrease reflected:

• $7 million in lower incentive compensation expense;

• $5 million in lower fees due to Oncor’s exit from the sale of accounts receivable program;

• $4 million in expenses in 2007 related to the rebranding of TXU Electric Delivery Company to Oncor Electric Delivery Company, and

• $1 million in decreased bad debt expense.

partially offset by $4 million in higher professional fees and $4 million in increased employee benefits costs.

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Franchise and revenue-based taxes decreased $4 million, or 2%, to $186 million in 2008. A decrease in state franchise taxes of $9 million due to the 2007 enactment of the Texas margin tax, which is accounted for as an income tax, was partially offset by a $5 million increase in local franchise fees reflecting increased volumes of electricity delivered. Local franchise fees resulting from the 2006 cities rate settlement totaled $7 million and $6 million for the nine months ended September 30, 2008 and 2007, respectively.

Other income totaled $34 million in 2008 and $3 million in 2007. The 2008 amount reflects accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. See “Regulatory Assets and Liabilities” in Note 15 to the September 30, 2008 Financial Statements for additional information.

Other deductions totaled $17 million in 2008 and $26 million in 2007. The 2008 amount includes:

• $13 million in costs as a result of the 2006 cities rate settlement, and

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

The 2007 amount includes:

• $19 million in costs a result of the 2006 cities rate settlement;

• $3 million in costs related to the cancelled InfrastruX Energy Services joint venture, and

• $2 million in equity losses (representing amortization expense) related to the ownership interest in an EFH Corp. subsidiary holding the capitalized software licensed to Capgemini.

Interest income decreased $8 million, or 19%, to $34 million in 2008. The decrease reflects $4 million in lower earnings on assets held for employee benefit plans, a $3 million decrease in reimbursement of transition bond interest from TCEH and a $1 million decrease in earnings on restricted cash.

Interest expense decreased $4 million, or 2%, to $229 million in 2008. Interest expense in 2008 reflected a decrease of $18 million due to lower average interest rates driven by increased short-term borrowings prior to the September 2008 issuance of $1.5 billion in senior secured notes (see Note 7 to the September 30, 2008 Financial Statements), partially offset by a $14 million effect of higher average borrowings, reflecting the ongoing capital investment in the business, including the purchase of an existing BPL-based “Smart Grid” network. The average interest rate effect is net of a $3 million increase due to the amortization of the fair value discount related to transition bonds that was recorded due to purchase accounting.

Income tax expense totaled $180 million in 2008 compared to $146 million in 2007. The effective income tax rate increased to 36.8% in 2008 from 35.6% in 2007. The increased rate is driven by a decrease in the benefit from the Medicare subsidy for post-employment benefits.

Net income increased $45 million, or 17%, to $309 million driven by increased revenues and higher other income, which reflects the effects of purchase accounting.

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

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2008. The net changes in these assets and liabilities, excluding “other activity” 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 10 to the September 30, 2008 Financial Statements). For the nine months ended September 30, 2008, this effect totaled $217 million in unrealized net losses, which represented $233 million in net losses from changes in fair value and

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$16 million in net gains representing reversals of previously recognized fair values of positions settled in the current period. These positions represent both economic hedging and trading activities.

	Successor
	Nine Months Ended September 30, 2008
Commodity contract net asset (liability) at beginning of period	$	(1,917	)
Settlements of positions (a)		16
Unrealized mark-to-market valuations of positions (b)		(233	)
Other activity (c)		(7	)
Commodity contract net asset (liability) at end of period	$	(2,141	)

(a) Represents reversals of fair values previously recognized to offset gains and losses realized upon settlement of the positions in the current period. Includes settlements of positions entered into in the current period and the expiration of option premiums during the current period.

(b) Primarily represents mark-to-market effects of positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”). Of this amount, $82 million in net losses relates to positions not settled as of the end of the period. Includes $68 million in net losses recorded at contract inception dates (see Note 10 to the September 30, 2008 Financial Statements).

(c) These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration.

Note: Of the $217 million in unrealized net losses for the period, $301 million in net losses are reported in the income statement as net loss from commodity hedging and trading activities. The difference of $84 million in net gains relate to physically settled sales and purchase transactions, with $155 million in net gains reported in revenues and $71 million in net losses reported in fuel, purchased power costs and delivery fees, as required by accounting rules.

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 included in net gain (loss) from commodity hedging and trading activities and reflected in the balance sheet as changes in commodity and other derivative contractual assets and liabilities (see Note 10 to the September 30, 2008 Financial Statements). The total pretax effect of recording unrealized gains and losses in net income related to commodity contracts under SFAS 133 is summarized as follows:

	Successor		Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008		Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Unrealized gains (losses) related to contracts marked-to-market	$	6,142	$	481		$	(217	)	$	(795	)
Ineffectiveness gains (losses) related to contracts accounted for as cash flow hedges (a)		—		(2	)		(4	)		92
Total unrealized gains (losses) related to commodity contracts	$	6,142	$	479		$	(221	)	$	(703	)

(a) See Note 10 to the September 30, 2008 Financial Statements.

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Maturity Table—Following are the components of the net commodity contract liability at September 30, 2008:

Net commodity contract liability	$	(2,141	)
Net receipts of natural gas under physical swap transactions		33
Amount of net liability arising from recognition of fair values	$	(2,108	)

The following table presents the net commodity contract liability arising from recognition of fair values as of September 30, 2008, scheduled by the source of fair value and contractual settlement dates of the underlying positions. See Note 12 to the September 30, 2008 Financial Statements for fair value disclosures required under SFAS 157.

	Maturity dates of unrealized commodity contract liabilities at September 30, 2008
Source of fair value (a)	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(158	)	$	(89	)	$	(20	)	$	—		$	(267	)
Prices provided by other external sources		50			(808	)		(806	)		(75	)		(1,639	)
Prices based on models		(7	)		(53	)		(40	)		(102	)		(202	)
Total	$	(115	)	$	(950	)	$	(866	)	$	(177	)	$	(2,108	)
Percentage of total fair value		6	%		45	%		41	%		8	%		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 over-the-counter traded options, valued using option pricing models. In addition, this category contains other contractual arrangements that may have forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. 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

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

	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Net increase (decrease) in fair value of cash flow hedges:
Commodities	$	(8	)	$	7		$	(7	)	$	(290	)
Financing—interest rate swaps		(133	)		—			(177	)		—
		(141	)		7			(184	)		(290	)
Derivative value net losses (gains) reported in net income that relate to hedged transactions recognized in the period:
Commodities		5			(11	)		7			(90	)
Financing—interest rate swaps		37			1			77			5
		42			(10	)		84			(85	)
Total loss effect of cash flow hedges reported in other comprehensive income	$	(99	)	$	(3	)	$	(100	)	$	(375	)

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 10 to the September 30, 2008 Financial Statements.

Results of Operations for the Year Ended December 31, 2007 and 2006

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 the 2007 year-end Financial Statements regarding discontinued operations).

Presentation and Analysis of Results

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 has been prepared by comparing the results of operations and cash flows of the Predecessor for the period January 1, 2007 through October 10, 2007 to the results of operations and cash flows of the Predecessor for the nine months ended September 30, 2006 and by analyzing the results of operations and cash flows of the Successor for the period October 11, 2007 through December 31, 2007 on a stand-alone basis. Certain volumetric and statistical data for 2007 have been presented as of and for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006 and as of and for the three months ended December 31, 2007. For reporting purposes, such volumetric and statistical data are measured on a monthly, quarterly and annual basis.

100

EFH Corp. Consolidated Financial Results

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Nine Months Ended September 30, 2006
Operating revenues (a)	$	1,994		$	8,044		$	8,420
Fuel, purchased power costs and delivery fees		(644	)		(2,381	)		(2,182	)
Net gain (loss) from commodity hedging and trading activities		(1,492	)		(554	)		61
Operating costs		(306	)		(1,107	)		(1,018	)
Depreciation and amortization		(415	)		(634	)		(628	)
Selling, general and administrative expenses		(216	)		(691	)		(582	)
Franchise and revenue-based taxes		(93	)		(282	)		(276	)
Other income		14			69			91
Other deductions		(61	)		(841	)		(244	)
Interest income		24			56			30
Interest expense and related charges		(839	)		(671	)		(640	)
Income (loss) from continuing operations before income taxes		(2,034	)		1,008			3,032
Income tax (expense) benefit		673			(309	)		(1,036	)
Income (loss) from continuing operations		(1,361	)		699			1,996
Income from discontinued operations, net of tax effect		1			24			81
Net income (loss) available for common stock	$	(1,360	)	$	723		$	2,077

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

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 are reflected in the table below:

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Nine Months Ended September 30, 2006
Competitive Electric segment:
Total retail electricity revenues	$	1,142		$	5,014		$	5,543
Wholesale electricity revenues		505			1,637			1,635
Wholesale balancing activities		(9	)		(14	)		(6	)
Amortization of intangibles (a)		(50	)		—			—
Other operating revenues		83			247			274
Total Competitive Electric segment		1,671			6,884			7,446
Regulated Delivery segment		532			1,987			1,874
Net intercompany eliminations		(209	)		(827	)		(900	)
Total consolidated revenues	$	1,994		$	8,044		$	8,420

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

101

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

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

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

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

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

Commodity hedging and trading activities resulted in a $554 million net loss in the Predecessor period from January 1, 2007 through October 10, 2007 compared to a $61 million net gain in the nine months ended September 30, 2006. The net loss in 2007 reflects unrealized mark-to-market net losses totaling $722 million driven by the effect of higher forward market prices of natural gas on positions in the long-term hedging program. See discussion above under “Long-Term Hedging Program” and below in the analysis of Competitive Electric segment results of operations.

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

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

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

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

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

102

Other income totaled $69 million in 2007 and $91 million in 2006. Other deductions totaled $841 million in 2007 and $244 million in 2006. The 2007 other deductions amount included net charges of $755 million related to the cancelled development of eight coal-fueled generation units (see Note 7 to the 2007 year-end Financial Statements). The 2006 other deductions amount includes a $198 million impairment charge related to natural gas-fueled generation units (see Note 8 to the 2007 year-end Financial Statements). See Note 15 to the 2007 year-end Financial Statements for details of other income and deductions.

Interest expense and related charges increased $31 million, or 5%, to $671 million in 2007, $27 million of the increase was attributable to the 10 additional days in the 2007 period compared to the 2006 period and reflected the borrowings associated with the Merger. The remaining increase reflected higher average borrowings, primarily to fund capital expenditures, largely offset by increased capitalized interest.

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

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

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

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

• Corporate and Other net expenses totaled $288 million in 2007 and $167 million in 2006. The amounts in 2007 and 2006 include recurring interest expense on outstanding debt and advances from subsidiaries, as well as corporate general and administrative expenses. The increase of $121 million (after-tax) primarily reflects $25 million in financial advisory, legal and other professional fees in 2007 directly related to the Merger, the write-off in 2007 of $25 million in previously deferred costs related to anticipated strategic transactions (including expected financings) that were no longer expected to be completed as a result of the Merger, and $33 million in nonrecurring gains in 2006 primarily related to the settlement of a telecommunications contract dispute, an insurance recovery of a litigation settlement and a gain on the sale of mineral rights. The increase in Corporate and Other net expenses also reflected higher 2007 expenses related to accrued interest on uncertain income tax positions and SG&A expenses driven by higher compensation and consulting expenses, partially offset by a deferred tax benefit related to the Texas margin tax as described in Note 13 to the 2007 year-end Financial Statements.

Successor Period from October 11, 2007 to December 31, 2007

Operating revenues for the Successor period of 2007 totaled $1.994 billion. Operating revenues of $1.671 billion in the Competitive Electric segment included retail electricity revenues of $1.142 billion, which were impacted by residential price discounts. Operating revenues of $532 million in the Regulated Delivery segment reflected growth in points of delivery and increased distribution and transmission tariffs. Net intercompany sales eliminations reflected the elimination of sales from Oncor to REP subsidiaries of TCEH.

Fuel, purchased power costs and delivery fees for the Successor period of 2007 totaled $644 million, which included $67 million of net expense representing amortization of the intangible net asset values of emission credits, coal purchase contracts and power purchase agreements and the stepped-up value of nuclear fuel resulting from purchase accounting.

103

Net losses from commodity hedging and trading activities of $1.492 billion were 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.

Operating costs for the Successor period of 2007 totaled $306 million, including operations and maintenance expenses for power generation plants, fees paid to other transmission providers and salaries and benefits for plant personnel.

Depreciation and amortization for the Successor period of 2007 totaled $415 million, which included $157 million of incremental depreciation expense resulting from stepped-up property, plant and equipment values and $81 million in incremental amortization expense related to the intangible value of retail customer relationships recorded in connection with purchase accounting and substantially all in the Competitive Electric segment.

SG&A expenses for the Successor period of 2007 totaled $216 million, which include retail sales and marketing expenses, administrative and general salaries and benefits and consulting and professional fees. Also included were $8 million of management fees paid to the Sponsor Group.

Other income for the Successor period of 2007 totaled $14 million, which consisted primarily of $10 million in accretion of an adjustment to regulatory assets resulting from purchase accounting. Other deductions for the Successor period of 2007 totaled $61 million and consisted primarily of professional fees incurred related to the Merger.

Interest expense and related charges for the Successor period of 2007 totaled $839 million, a substantial portion of which was driven by borrowings for Merger-related financings.

Income tax benefit on loss from continuing operations for the Successor period of 2007 totaled $673 million. The effective income tax rate of 33.1% reflects the impact of non-deductible Merger-related transaction costs and interest accrued related to uncertain tax positions.

Loss from continuing operations (an after-tax measure) for the Successor period of 2007 totaled $1.361 billion. The loss in the Competitive Electric segment totaled $1.245 billion, which was driven by unrealized mark-to-market net losses on positions in the long-term hedging program, interest expense on Merger-related debt and the effects of purchase accounting. Income in the Regulated Delivery segment totaled $63 million, and Corporate and Other net expenses totaled $179 million.

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.

104

EFH Corp.’s operating revenues decreased $123 million, or 1%, to $10.703 billion in 2006 as shown in the table below:

	Predecessor
	Year Ended December 31,						Increase (Decrease)
	2006			2005
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	)
Other operating revenues		358			354			4
Total Competitive Electric segment		9,396			9,716			(320	)
Regulated Delivery segment		2,449			2,394			55
Net intercompany eliminations		(1,142	)		(1,284	)		142
Total consolidated revenues	$	10,703		$	10,826		$	(123	)

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 the 2007 year-end 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 the 2007 year-end 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 the 2007 year-end Financial Statements for a discussion regarding reporting of ERCOT balancing 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.

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 2007 year-end Financial Statements.

The net gain arising from risk management and trading activities in 2006 primarily reflects 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. See discussion below in the analysis of Competitive Electric segment results of operations.

105

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 the 2007 year-end 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) 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.

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 the 2007 year-end 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 the 2007 year-end 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 2007 year-end 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 2007 year-end Financial Statements and $29 million benefit (1.2 percentage point effective tax rate impact) related to the release of a tax reserve.

106

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 decreased fuel, purchased power costs and delivery fees 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 the 2007 year-end 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 the 2007 year-end Financial Statements for details.

Competitive Electric Segment

The following tables present financial operating results of the Competitive Electric segment for the Successor period from October 11, 2007 through December 31, 2007 and for the Predecessor periods from January 1, 2007 through October 10, 2007, the nine months ended September 30, 2006 and the years ended December 31, 2006 and 2005. Volumetric and other statistical data have been presented for the Predecessor period for the nine months ended September 30, 2007 and 2006 and for the years ended December 31, 2006 and 2005.

Financial Results

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Nine Months Ended September 30, 2006			Year Ended December 31,
										2006			2005
Operating revenues	$	1,671		$	6,884		$	7,446		$	9,396		$	9,716
Fuel, purchased power costs and delivery fees		(852	)		(3,209	)		(3,081	)		(3,928	)		(5,545	)
Net gain (loss) from commodity hedging and trading activities		(1,492	)		(554	)		61			153			(164	)
Operating costs		(124	)		(471	)		(442	)		(604	)		(668	)
Depreciation and amortization		(315	)		(253	)		(252	)		(334	)		(313	)
Selling, general and administrative expenses		(154	)		(489	)		(403	)		(571	)		(522	)
Franchise and revenue-based taxes		(30	)		(81	)		(84	)		(126	)		(114	)
Other income		2			22			5			23			64
Other deductions		(8	)		(735	)		(205	)		(215	)		(15	)
Interest income		10			271			137			203			70
Interest expense and related charges		(609	)		(357	)		(316	)		(389	)		(393	)
Income (loss) from continuing operations before income taxes, extraordinary loss and cumulative effect of changes in accounting principles
		(1,901	)		1,028			2,866			3,608			2,116
Income tax (expense) benefit		656			(306	)		(985	)		(1,241	)		(687	)
Income (loss) from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles	$	(1,245	)	$	722		$	1,881		$	2,367		$	1,429

107

Competitive Electric Segment

Sales Volume and Customer Count Data

				Predecessor						Predecessor
	Three Months Ended December 31, 2007			Nine Months Ended September 30,						Year Ended December 31,
				2007			2006			2006			2005
Sales volumes:
Retail electricity sales volumes—gigawatt hours (GWh):
Residential		5,967			21,256			23,770			29,595			32,655
Small business (a)		1,622			5,861			6,716			8,424			9,678
Large business and other customers		3,591			10,946			10,703			14,031			15,843
Total retail electricity		11,180			38,063			41,189			52,050			58,176
Wholesale electricity sales volumes		11,198			27,914			25,870			36,931			52,001
Net sales (purchases) of balancing electricity to/from ERCOT (b)		47			622			1,268			874			4,787
Total sales volumes		22,425			66,599			68,327			89,855			114,964
Average volume (kWh) per retail customer (c):
Residential		3,197			11,399			12,235			15,359			15,825
Small business		6,337			22,421			23,926			30,360			32,078
Large business and other customers		104,582			276,764			210,515			285,277			243,538
Weather (service territory average)—percent of normal (d):
Percent of normal:
Cooling degree days		—			94.2	%		118.5	%		117.6	%		107.0	%
Heating degree days		89.7	%		—			—			79.2	%		90.0	%
Average revenues per MWh:
Residential	$	127.87		$	138.99		$	148.44		$	147.43		$	117.86
Customer counts:
Retail electricity customers (end of period and in thousands) (e):
Residential		1,875			1,858			1,904			1,871			1,982
Small business (a)		256			256			273			267			288
Large business and other customers		33			35			47			44			55
Total retail electricity customers		2,164			2,149			2,224			2,182			2,325

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

(b) See Note 1 to the 2007 year-end Financial Statements for discussion of trading and ERCOT balancing activity.

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

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

(e) Based on number of meters.

108

Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Nine Months Ended September 30, 2006			Year Ended December 31,
										2006			2005
Operating revenues:
Retail electricity revenues:
Residential	$	654		$	3,064		$	3,528		$	4,363		$	3,849
Small business (a)		202			880			984			1,233			1,151
Large business and other customers		286			1,070			1,031			1,357			1,330
Total retail electricity revenues		1,142			5,014			5,543			6,953			6,330
Wholesale electricity revenues (b)		505			1,637			1,635			2,278			2,807
Net sales (purchases) of balancing electricity to/from ERCOT (b)		(9	)		(14	)		(6	)		(31	)		225
Amortization of intangibles (c)		(50	)		—			—			—			—
Other operating revenues (d)		83			247			274			196			354
Total operating revenues	$	1,671		$	6,884		$	7,446		$	9,396		$	9,716
Commodity hedging and trading activities:
Unrealized net gains (losses), including cash flow hedge ineffectiveness from changes in fair value (e)	$	(1,469	)	$	(646	)	$	203		$	228		$	2
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the current period (e)		(87	)		(76	)		11			44			(20	)
Realized net gains (losses) on settled positions (f)		64			168			(153	)		(119	)		(146	)
Total gain (loss)	$	(1,492	)	$	(554	)	$	61		$	153		$	(164	)

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

(b) See Note 1 to the 2007 year-end Financial Statements for discussion of reporting of trading and ERCOT balancing activity.

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

(d) Includes a $162 million charge for a special customer appreciation bonus in 2006. This charge does not affect the computation of residential average revenues per MWh. See Note 9 to the 2007 year-end Financial Statements.

(e) Amounts have been reclassified to include effects of changes in fair values of positions entered into and settled within the period; this change was made in association with the reclassification of commodity hedging and trading activities discussed in Note 1 to the 2007 year-end 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, $29 million in net losses for the nine months ended September 30, 2006, $34 million in net losses for 2006 and $61 million in net gains for 2005.

109

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Successor		Predecessor
	Period from October 11, 2007 through December 31, 2007		Period From January 1, 2007 through October 10, 2007		Nine Months Ended September 30, 2006		Year Ended December 31,
							2006		2005
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	21	$	66	$	65	$	85	$	78
Lignite/coal		127		467		353		475		475
Total baseload fuel		148		533		418		560		553
Natural gas fuel and purchased power		302		1,435		1,429		1,787		3,285
Amortization of intangibles (a)		67		—		—		—		—
Other costs		68		213		169		228		281
Fuel and purchased power costs (b)		585		2,181		2,016		2,575		4,119
Delivery fees (c)		267		1,028		1,065		1,353		1,426
Total	$	852	$	3,209	$	3,081	$	3,928	$	5,545

				Predecessor						Predecessor
	Three Months Ended December 31, 2007			Nine Months Ended September 30,						Year Ended December 31,
				2007			2006			2006			2005
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	4.64		$	4.59		$	4.25		$	4.29		$	4.23
Lignite/coal (d)	$	13.48		$	14.31		$	11.60		$	11.73		$	11.68
Natural gas fuel and purchased power	$	60.04		$	62.29		$	65.71		$	62.99		$	60.37
Delivery fees per MWh	$	26.64		$	25.60		$	25.60		$	25.71		$	24.20
Production and purchased power volumes (GWh):
Nuclear		5,157			13,664			15,292			19,795			18,371
Lignite/coal		12,197			34,297			34,252			45,579			45,933
Total baseload generation		17,354			47,961			49,544			65,374			64,304
Natural gas-fueled generation		500			3,491			3,487			3,989			3,504
Purchased power (b)		5,483			18,619			18,258			24,380			50,920
Total energy supply		23,337			70,071			71,289			93,743			118,728
Less line loss and power imbalances		912			3,472			2,962			3,888			3,764
Net energy supply volumes		22,425			66,599			68,327			89,855			114,964
Baseload capacity factors (%):
Nuclear		101.6	%		90.8	%		102.0	%		98.8	%		91.5	%
Lignite/coal		94.5	%		89.7	%		89.5	%		89.1	%		89.8	%
Total baseload		96.5	%		90.0	%		93.1	%		91.8	%		90.3	%

(a) 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.

(b) See Note 1 to the 2007 year-end Financial Statements for discussion of reporting of trading and ERCOT balancing activity.

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

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

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Competitive Electric Segment—Financial Results—2007

Operating revenues are shown in the following table:

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Nine Months Ended September 30, 2006
Total retail electricity revenues	$	1,142		$	5,014		$	5,543
Wholesale electricity revenues		505			1,637			1,635
Wholesale balancing activities		(9	)		(14	)		(6	)
Amortization of intangibles (a)		(50	)		—			—
Other operating revenues		83			247			274
Total operating revenues	$	1,671		$	6,884		$	7,446

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

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

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

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

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

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

The decrease in retail electricity revenues was partially offset by $186 million in revenues attributable to the ten additional days in the 2007 period compared to the 2006 period.

Wholesale electricity revenues increased $2 million. $66 million of revenue in 2007 was attributable to the ten additional days in the period compared to the 2006 period. For the nine month periods, wholesale electricity revenues reflected lower prices as average wholesale prices declined approximately 11% reflecting lower natural gas prices during 2007, the effect of which was partially offset by volume growth of 8% due in part to the decline in retail sales volumes associated with competitive activity.

Wholesale 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.

Fuel, purchased power costs and delivery fees increased $128 million, or 4%, to $3.209 billion, with $123 million of the increase attributable to the ten additional days in the 2007 period compared to the 2006 period. As a percentage of revenue, fuel, purchased power costs and delivery fees were 47% in the 2007 period compared to 41% in the 2006 period.

111

The change reflected increased purchases of power due to a scheduled refueling and major maintenance outage for one of the two Comanche Peak nuclear units and higher lignite mining costs due to inefficiencies caused by significantly above normal summer rainfall.

Results from commodity hedging and trading activities include realized and unrealized gains and losses associated with financial instruments used for commodity hedging and trading purposes, as well as gains and losses on physical sales and purchases of commodities for trading and certain commodity hedging purposes. A substantial majority of the commodity hedging activities are intended to mitigate the risk of commodity price movements on future revenues and involve natural gas positions entered into as part of the long-term hedging program. The results of these activities have been volatile because of the effects of movements in forward natural gas prices on unrealized mark-to-market valuations. Following is an analysis of activities for the period from January 1, 2007 through October 10, 2007 and for the nine months ended September 30, 2006:

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

• $536 million in net losses related to hedge positions, which includes $498 million in net losses from changes in fair values and $38 million in net losses that represent reversals of previously recorded fair values of positions settled in the period. These losses are driven by the effect of higher natural gas prices in forward periods on positions in the long-term hedging program;

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

• $75 million in net losses related to trading positions, which includes $58 million in net losses from changes in fair values and $17 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;

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

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

Realized net gains totaling $168 million include:

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

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

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

• $52 million in net losses related to hedge positions, which includes $10 million in net losses from changes in fair values and $42 million in net losses that represent reversals of previously recorded fair values of positions settled in the period. These losses are driven by the effect of higher natural gas prices in forward periods on positions in the long-term hedging program;

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

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

112

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

Realized net losses totaling $153 million include:

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

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

Operating costs increased $29 million, or 7%, to $471 million in 2007. $19 million of the increase was attributable to the ten additional days in the 2007 period compared to the 2006 period. For the nine month periods, higher operating costs reflected $18 million in higher generation maintenance costs largely due to the scheduled outage in the spring of 2007 of one of the Comanche Peak nuclear generation units and $7 million for the utilization of SO₂ emission credits in 2007 for the lignite/coal-fueled generation units, partially offset by lower costs largely resulting from generation technical support outsourcing service agreements.

Depreciation and amortization increased $1 million for the period. $8 million of expense in the 2007 period was attributable to the ten additional days in the 2007 period compared to the 2006 period. For the nine month periods, lower depreciation and amortization was driven 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, partially offset by higher baseload generation plant depreciation, driven by ongoing investments in property, plant and equipment.

SG&A expenses increased $86 million, or 21%, to $489 million in 2007. $15 million of the increase was attributable to the ten additional days in the 2007 period compared to the 2006 period. For the nine month periods, higher SG&A expenses reflected $27 million in increased retail marketing expenses, $16 million in costs associated with the new generation facilities development program, principally salaries and consulting expenses, and $14 million in higher professional fees primarily for retail billing and customer care systems enhancements and marketing/strategic projects. The increase was also due to higher salary and benefit costs primarily driven by an increase in staffing in retail operations and higher costs due to reallocation of Capgemini outsourcing fees. Partially offsetting the increase in SG&A expenses were lower bad debt expenses driven by a decrease in delinquencies and lower accounts receivable balances.

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

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

• net charges of $755 million related to the cancelled development of eight coal-fueled generation units (see Note 7 to the 2007 year-end Financial Statements);

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

• a $48 million credit from reducing a liability previously recorded for leases related to gas-fueled combustion turbines that EFH Corp. ceased operating for its own benefit (see Note 5 to the 2007 year-end 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 the 2007 year-end Financial Statements), and

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

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

113

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

Interest expense and related charges increased by $41 million to $357 million in 2007. $15 million of the increase was attributable to the ten additional days in the 2007 period compared to the 2006 period. For the nine month periods, higher expenses reflected $53 million due to higher average borrowings and $20 million due to higher average interest rates, partially offset by $47 million in increased capitalized interest.

Income tax expense totaled $306 million in 2007 compared to $985 million in 2006. Excluding the $32 million deferred tax benefit in 2007 and the $42 million deferred tax charge in 2006 related to the Texas margin tax as described in Note 13 to the 2007 year-end Financial Statements, the effective income tax rate was 32.9% in both 2007 and 2006. (These unusual deferred tax adjustments distort the comparison; they have therefore been excluded for purposes of a more meaningful discussion.)

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

Successor Period from October 11, 2007 to December 31, 2007

Operating revenues for the Successor period of 2007 totaled $1.671 billion. Retail electricity revenues of $1.142 billion were impacted by lower average pricing driven by a 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. Wholesale electricity revenues of $505 million reflect lower prices resulting from lower natural gas prices in 2007.

Fuel, purchased power costs and delivery fees for the Successor period of 2007 totaled $852 million or 51% of revenues. This amount included $67 million of net expense representing amortization of the intangible net asset values of emission credits, coal purchase contracts and power purchase agreements and the stepped-up value of nuclear fuel resulting from purchase accounting.

Net losses from commodity hedging and trading activities totaled $1.492 billion and reflected the following:

Unrealized mark-to-market net losses of $1.556 billion include:

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

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

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

Realized net gains totaling $64 million include:

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

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

Operating costs for the Successor period of 2007 totaled $124 million and primarily reflected operations and maintenance expenses for power generation plants and salaries and benefits for plant personnel.

114

Depreciation and amortization expense for the Successor period of 2007 totaled $315 million and included $157 million of incremental depreciation expense resulting from stepped-up property, plant and equipment values and $79 million in incremental amortization expense related to the intangible value of retail customer relationships recorded in connection with purchase accounting.

SG&A expense for the Successor period of 2007 totaled $154 million and includes retail sales and marketing expenses, administrative and general salaries and benefits and consulting and professional fees.

Interest expense and related charges for the Successor period of 2007 totaled $609 million, a substantial portion of which represented interest on borrowings for Merger-related financings.

Income tax benefit for the Successor period of 2007 was $656 million and the effective income tax rate was 34.5%.

Results from continuing operations were a loss of $1.245 billion reflecting unrealized mark-to-market net losses on positions in the long-term hedging program, interest expense driven by Merger-related debt and the effects of purchase accounting.

Competitive Electric Segment Financial Results—2006 compared to 2005

Operating revenues decreased $320 million, or 3%, to $9.396 billion in 2006, as shown in the following table.

	Predecessor
	Year Ended December 31,					Increase (Decrease)
	2006			2005
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	)
Other operating revenues		358			354		4
Total operating revenues	$	9,396		$	9,716	$	(320	)

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 the 2007 year-end Financial Statements.

115

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 the 2007 year-end 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 to the 2007 year-end Financial Statements for a discussion regarding the change in reporting of ERCOT balancing activities.

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 2007 year-end Financial Statements and the favorable impact of higher nuclear generation volumes to meet sales demand in an environment of increasing wholesale power prices, partially offset by the effect of higher average prices of purchased electricity.

Following is an analysis of commodity hedging 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 $231 million in net gains from changes in fair values and $8 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);

• $94 million in net gains related to trading positions, which includes $39 million in net gains from changes in fair values and $55 million in net gains that represent reversals of previously recorded fair values of positions settled in the period;

• $47 million in net gains related to hedge positions, which includes $66 million in net gains from changes in fair values and $19 million in net losses that represent reversals of previously recorded fair values of positions settled in the period; 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 $31 million in net losses from changes in fair values and $4 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.

116

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 the 2007 year-end 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) 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.

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.

117

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 the 2007 year-end 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 2007 year-end 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 decreased fuel, purchased power costs and delivery fees 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.

118

Regulated Delivery Segment

The following tables present financial operating results of the Regulated Delivery segment for the Successor period from October 11, 2007 through December 31, 2007 and for the Predecessor periods from January 1, 2007 through October 10, 2007, for the nine months ended September 30, 2006 and for the years ended December 31, 2006 and 2005. Volumetric and other statistical data have been presented for the Predecessor period for the nine months ended September 30, 2007 and 2006 and for the years ended December 31, 2006 and 2005.

Financial Results

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Nine Months Ended September 30,			Year Ended December 31,
							2006			2006			2005
Operating revenues	$	532		$	1,987		$	1,874		$	2,449		$	2,394
Operating costs		(182	)		(637	)		(579	)		(770	)		(758	)
Depreciation and amortization		(96	)		(366	)		(359	)		(476	)		(446	)
Selling, general and administrative expenses		(45	)		(139	)		(138	)		(177	)		(201	)
Franchise and revenue-based taxes		(62	)		(198	)		(189	)		(262	)		(247	)
Other income		11			3			2			2			4
Other deductions		(7	)		(27	)		(13	)		(24	)		(11	)
Interest income		12			44			43			58			59
Interest expense and related charges		(70	)		(242	)		(213	)		(286	)		(269	)
Income before income taxes		93			425			428			514			525
Income tax expense		(30	)		(160	)		(146	)		(170	)		(174	)
Net income	$	63		$	265		$	282		$	344		$	351

Regulated Delivery Segment

Operating Data

	Three Months Ended December 31, 2007	Predecessor
		Nine Months Ended September 30,		Year Ended December 31,
		2007	2006	2006	2005
Operating statistics—volumes:
Electric energy delivered (GWh)	24,622	81,523	83,480	107,098	106,780
Reliability statistics (a):
System Average Interruption Duration Index (SAIDI) (nonstorm)	77.88	79.22	78.29	79.09	76.79
System Average Interruption Frequency Index (SAIFI) (nonstorm)	1.10	1.14	1.16	1.17	1.17
Customer Average Interruption Duration Index (CAIDI) (nonstorm)	70.64	69.51	67.31	67.54	65.60
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters)	3,093	3,087	3,051	3,056	3,013

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	Successor		Predecessor
	Period from October 11, 2007 through December 31, 2007		Period From January 1, 2007 through October 10, 2007		Nine Months Ended September 30, 2006		Year Ended December 31,
							2006		2005
Operating revenues:
Electricity distribution revenues (b):
Affiliated (TCEH)	$	208	$	821	$	894	$	1,137	$	1,276
Nonaffiliated		257		921		782		1,046		879
Total distribution revenues		465		1,742		1,676		2,183		2,155
Third-party transmission revenues		60		199		176		236		213
Other miscellaneous revenues		8		45		22		30		26
Total operating revenues	$	533	$	1,986	$	1,874	$	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) 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, $117 million for the nine months ended September 30, 2006 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.

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, $10 million for the nine months ended September 30, 2006 and $18 million for the year ended December 31, 2006.

Regulated Delivery Segment Financial Results—2007

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

Operating revenues increased $113 million, or 6%, to $1.987 billion in 2007. $68 million of the increase was attributed to the ten additional days in the 2007 period compared to the 2006 period. For the nine month periods, higher revenues reflected:

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

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

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

partially offset by,

• $16 million effect of lower average consumption due in part to cooler, below normal summer weather in 2007 and hotter than normal weather in 2006, net of the impact of increased points of delivery, and

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

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Operating costs increased $58 million, or 10%, to $637 million in 2007. $21 million of the increase was attributed to the ten additional days in the 2007 period compared to the 2006 period. For the nine month periods, higher costs reflected $26 million in higher fees paid to other transmission entities, $18 million in equipment installation costs for a third party that will facilitate Oncor’s technology initiatives, higher labor-related costs due to timing of equipment installation activities and increased labor cost primarily for restoration of service as a result of weather events, partially offset by lower vegetation management expenses.

Depreciation and amortization increased $7 million, or 2%, to $366 million in 2007 which was primarily due to the 10 additional days in 2007 and ongoing investments in property, plant and equipment, partially offset by a one-time adjustment related to retired property and lower amortization of the regulatory assets associated with the securitization bonds (offset in revenue).

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

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

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

Interest expense increased $29 million, or 14%, to $242 million in 2007. $9 million of the increase was due to the 10 additional days in the 2007 period compared to the 2006 period. For the nine month periods, higher interest expense reflected $14 million due to higher average borrowings, reflecting the ongoing capital investment in the business, and $5 million due to higher average interest rates.

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

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

Successor Period from October 11, 2007 to December 31, 2007

Operating revenues for the Successor period of 2007 of $532 million reflected growth in points of delivery and rate increases approved in 2006 and 2007 to recover ongoing investment in the transmission system.

Operating costs for the Successor period of 2007 totaled $182 million, which included approximately $75 million in fees paid to other transmission providers, as well as labor-related costs due to equipment installation activities and vegetation management expenses.

Depreciation and amortization for the Successor period of 2007 totaled $96 million.

SG&A expenses for the Successor period of 2007 totaled $45 million, which included administrative and general salaries and benefits and consulting and professional fees.

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Franchise and revenue-based taxes for the Successor period of 2007 totaled $62 million, which included local franchise fees of $2 million resulting from the 2006 cities rate settlement.

Other income for the Successor period of 2007 totaled $11 million, which included $10 million of accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting.

Interest expense and related charges for the Successor period of 2007 totaled $70 million, which reflected $5.1 billion in average borrowings at an average interest rate of 6.18%.

Income tax expense for the Successor period of 2007 totaled $30 million and the effective tax rate was 32.3%. The effective tax rate reflected Texas state income taxes and interest accrued related to uncertain tax positions.

Net income for the Successor period of 2007 totaled $63 million.

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.

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) 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 the 2007 year-end Financial Statements.

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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 the 2007 year-end 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.

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.

Energy-Related Commodity Contracts and Mark-to-Market Activities—The table below summarizes the changes in commodity contract assets and liabilities for the Successor period from October 11, 2007 through December 31, 2007, and for the Predecessor periods from January 1, 2007 through October 10, 2007, the nine months ended September 30, 2006 and the years ended December 31, 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 the 2007 year-end Financial Statements). These positions represent both economic hedging and trading activities.

	Successor			Predecessor
	October 11, 2007 through December 31, 2007			January 1, 2007 through October 10, 2007			Nine Months Ended September 30, 2006			Year Ended December 31, 2006			Year Ended December 31, 2005
Commodity contract net asset (liability) at beginning of period	$	(920	)	$	(23	)	$	(56	)	$	(56	)	$	23
Fair value adjustments at Merger closing date (a)		144			—			—			—			—
Reclassification at Merger closing date (b)		400			—			—			—			—
Settlements of positions (c)		(87	)		(55	)		(1	)		36			(24	)
Unrealized mark-to-market valuations of positions (d)		(1,469	)		(757	)		(86	)		(3	)		33
Other activity (e)		15			(85	)		(16	)		—			(88	)
Commodity contract net asset (liability) at end of period	$	(1,917	)	$	(920	)	$	(159	)	$	(23	)	$	(56	)

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(a) Represents adjustments arising primarily from the adoption of SFAS 157 (largely nonperformance risk effect—see Note 24 to the 2007 year-end Financial Statements).

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

(c) Represents reversals of fair values recognized to offset gains and losses realized upon settlement of the positions in the current period. Includes settlements of positions entered into in the current period to conform to current presentation. This change was made in association with the reclassification of commodity hedging and trading activities discussed in Note 1 to the 2007 year-end Financial Statements.

(d) 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, a $109 million loss in the nine months ended September 30, 2006 and $106 million in net losses in 2006 recorded at contract inception dates (see Note 20 to the 2007 year-end Financial Statements). Includes positions entered into and settled in the current period to conform to current presentation. This change was made in association with the reclassification of commodity hedging and trading activities discussed in Note 1 to the 2007 year-end Financial Statements.

(e) 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 the 2007 year-end 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 the nine months ended September 30, 2006 included a $25 million loss related to physical gas exchanges offset by a $9 million gain related to net premium activity. 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.

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 the 2007 year-end Financial Statements). The total pretax effect of recording unrealized gains and losses in net income related to commodity contracts under SFAS 133 is summarized as follows:

	Successor			Predecessor
	October 11, 2007 through December 31, 2007			January 1, 2007 through October 10, 2007			Nine Months Ended September 30, 2006			Year Ended December 31, 2006		Year Ended December 31, 2005
Unrealized gains/(losses) related to contracts marked-to-market	$	(1,556	)	$	(812	)	$	(87	)	$	33	$	9
Ineffectiveness gains/(losses) related to cash flow hedges (a)		—			90			301			239		(27	)
Total unrealized gains (losses) related to commodity contracts	$	(1,556	)	$	(722	)	$	214		$	272	$	(18	)

(a) See Note 20 to the 2007 year-end Financial Statements.

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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	)

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 the 2007 year-end 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 that utilize certain market based inputs. 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

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

	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
Net increase (decrease) in fair value of cash flow hedges:
Commodities	$	5		$	(288	)	$	598		$	(100	)
Financing—interest rate swaps		(182	)		—			—			—
		(177	)		(288	)		598			(100	)
Derivative value net losses (gains) reported in net income that relate to hedged transactions recognized in the period:
Commodities		—			(95	)		(53	)		117
Financing—interest rate swaps		—			6			8			13
		—			(89	)		(45	)		130
Total income (loss) effect of cash flow hedges reported in other comprehensive income	$	(177	)	$	(377	)	$	553		$	30

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 the 2007 year-end Financial Statements.

Liquidity and Capital Resources

Cash Flows—Nine Months Ended September 30, 2008 and 2007—Cash provided by operating activities from continuing operations totaled $957 million in the nine months ended September 30, 2008 compared to cash provided by operating activities of $1.555 billion in the nine months ended September 30, 2007. The decrease in cash provided of $598 million largely reflects:

• a $1.612 billion increase in cash interest payments,

partially offset by:

• a $533 million favorable change in margin deposits primarily due to the effect of lower forward natural gas prices on positions in the long-term hedging program. The majority of the margin deposits are funded by borrowings from the TCEH Commodity Collateral Posting Facility as discussed in Note 7 to the September 30, 2008 Financial Statements;

• a $331 million decrease in cash income taxes paid, and

• a $102 million premium paid in 2007 related to a structured natural gas-related option transaction entered into as part of EFH Corp.’s long-term hedging program.

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Cash provided by financing activities increased $1.729 billion as summarized below:

	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Net issuances, repayments and repurchases of borrowings	$	3,005		$	2,039
Net issuances and repurchases of common stock		33			(12	)
Common stock dividends paid		—			(594	)
Settlements of minimum withholding tax liabilities under stock-based incentive compensation plans		—			(93	)
Debt discount, financing and reacquisition expenses		(19	)		(17	)
Other		33			—
Total provided by financing activities	$	3,052		$	1,323

Cash used in investing activities decreased $153 million as summarized below:

	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Capital expenditures, including nuclear fuel purchases	$	(2,179	)	$	(2,450	)
Investment held in money market fund		(242	)		—
Proceeds from sale of assets		53			6
Change in restricted cash		1			181
Other		(7	)		(22	)
Total used in financing activities	$	(2,374	)	$	(2,285	)

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $337 million and $48 million for the nine months ended September 30, 2008 and 2007, respectively. The 2008 difference 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, purchased power costs and delivery fees, other income and interest expense and related charges. The 2008 and 2007 differences also reflect the amortization of nuclear fuel, which is reported as fuel cost in the statement of income consistent with industry practice.

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Cash Flows—Years ended 2007, 2006 and 2005—Cash flows from operating, financing and investing activities included:

	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Nine Months Ended September 30, 2006			Year Ended December 31,
										2006			2005
Cash flows—operating activities
Net income (loss)	$	(1,360	)	$	723		$	2,077		$	2,552		$	1,722
Income from discontinued operations, net of tax effect		(1	)		(24	)		(81	)		(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		(1,361	)		699			1,996			2,465			1,775
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Depreciation and amortization		568			684			676			893			836
Deferred income tax expense (benefit)—net		(736	)		(111	)		712			756			481
Impairment of natural gas-fueled generation plants		—			—			198			198			—
Customer appreciation bonus charge (net of amounts credited to customers in 2006)		—			—			—			122			—
Net charges related to cancelled development of generation facilities		2			676			—			—			—
Net effect of unrealized mark-to-market valuations—losses (gains)		1,556			722			(214	)		(272	)		18
Other, net		16			52			37			52			(65	)
Changes in operating assets and liabilities		(495	)		(457	)		640			740			(252	)
Cash provided by (used in) operating activities	$	(450	)	$	2,265		$	4,045		$	4,954		$	2,793
Cash flows—financing activities
Equity financing from Sponsor Group and other investors	$	8,236		$	—		$	—		$	—		$	—
Net issuances and redemptions of borrowings, including debt issuance costs, premiums and discounts		25,629			2,287			(992	)		(777	)		356
Net repurchases of common stock, preference stock and preferred securities of subsidiaries		—			(12	)		(773	)		(832	)		(1,392	)
Common and preference stock dividends paid		—			(788	)		(575	)		(764	)		(555	)
Excess tax benefit on stock-based incentive compensation		—			—			47			41			28
Settlements of minimum withholding tax liabilities under stock-based incentive compensation plans		—			(93	)		(59	)		—			—
Cash provided by (used in) financing activities	$	33,865		$	1,394		$	(2,352	)	$	(2,332	)	$	(1,563	)
Cash flows—investing activities
Acquisition of EFH Corp.	$	(32,694	)	$	—		$	—		$	—		$	—
Capital expenditures, including purchases of mining-related assets and nuclear fuel		(707	)		(2,517	)		(1,486	)		(2,297	)		(1,104	)
Proceeds from TCEH senior secured letter of credit facility deposited with bank		(1,250	)		—			—			—			—
Reduction of restricted cash		13			202			—			—			—
Proceeds from pollution control revenue bonds deposited with trustee		—			—			(99	)		(240	)		—
Other		75			32			(120	)		(127	)		66
Cash used in investing activities	$	(34,563	)	$	(2,283	)	$	(1,705	)	$	(2,664	)	$	(1,038	)
Cash provided by (used in) discontinued operations	$	(7	)	$	35		$	(1	)	$	30		$	(261	)
Net change in cash and cash equivalents	$	(1,155	)	$	1,411		$	(13	)	$	(12	)	$	(69	)

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Successor Period from October 11, 2007 through December 31, 2007—Cash used in operating activities totaled $450 million. The use of operating cash reflected $614 million in net margin deposits, which was largely funded by the Commodity Collateral Posting Facility, due primarily to the effect of increases in forward natural gas prices on positions in the long-term hedging program and use of working capital of $296 million, partially offset by operating earnings.

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

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

• a $1.149 billion unfavorable change in net margin deposits due to the effect of higher forward natural gas prices, primarily related to the long-term hedging program.

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005—The $2.161 billion increase in cash provided by operating activities 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 from 2005 through 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 $153 million, $50 million, $48 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, the nine months ended September 30, 2006 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.

129

Debt Financing Activity—Activities related to short-term borrowings and long-term debt during the nine months ended September 30, 2008 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capital leases):

	Borrowings		Repayments and Repurchases
TCEH	$	1,277	$	396
EFC Holdings		—		3
EFH Corp.		—		208
Oncor		1,500		67
Total long-term		2,777		674
TCEH		2,032		—
Oncor		—		1,130
Total short-term (a)		2,032		1,130
Total	$	4,809	$	1,804

(a) Short-term amounts represent net borrowings.

See Note 17 to the 2007 year-end Financial Statements and Note 7 to the September 30, 2008 Financial Statements for further detail of long-term debt and other financing arrangements.

EFH Corp. or its affiliates may from time to time purchase outstanding debt securities for cash in open market purchases, privately negotiated transactions or other transactions. EFH Corp. will evaluate any such transactions in light of market prices of the securities, taking into account its liquidity requirements and prospects for future access to capital, contractual restrictions and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material.

Credit Facilities—The following table summarizes changes in liquidity available under EFH Corp.’s committed credit facilities for the year-to-date period ended October 31, 2008:

	Availability
	December 31, 2007		October 31, 2008(a)		Change
TCEH Delayed Draw Term Loan Facility	$	1,950	$	842	$	(1,108	)
TCEH Revolving Credit Facility	$	2,636	$	1,166	$	(1,470	)
Total TCEH	$	4,586	$	2,008	$	(2,578	)
Oncor Revolving Credit Facility	$	720	$	1,650	$	930

(a) The TCEH Delayed Draw Term Loan Facility includes $14 million of undrawn commitments from a subsidiary of Lehman Brothers Holdings Inc. and excludes $2 million of requested draws by TCEH that have not been funded by the Lehman subsidiary as of October 31, 2008. The TCEH Revolving Credit Facility includes $134 million of undrawn commitments from the Lehman subsidiary and excludes $35 million of requested draws by TCEH that have not been funded by the Lehman subsidiary as of October 31, 2008. The Oncor Revolving Credit Facility includes $142 million of undrawn commitments from the Lehman subsidiary and excludes $17 million of requested draws by Oncor that have not been funded by the Lehman subsidiary.

The TCEH Delayed Draw Term Loan Facility is used to fund certain specified expenditures, principally related to the construction of the new generation facilities, and related expenses. The TCEH Revolving Credit Facility is used for working capital and other general corporate purposes. The TCEH Letter of Credit Facility is used for issuing letters of credit for general corporate purposes and had availability of $357 million of letters of

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credit as of October 31, 2008. During September and October 2008, TCEH borrowed approximately $2.3 billion under its Revolving Credit Facility, of which approximately $1 billion was repaid from October 28 through October 31, 2008. As of October 31, 2008, TCEH held cash and cash equivalents totaling $1.320 billion and a $242 million investment in a money market fund being liquidated (as described in Note 15 to the September 30, 2008 Financial Statements). (In November 2008, TCEH received $101 million of its $242 million investment in the money market fund, and it was announced that the U.S. Treasury, through the Exchange Stabilization Fund, has agreed to purchase any securities remaining in the money market fund on January 3, 2009.) EFH Corp. has unlimited availability under the committed TCEH Commodity Collateral Posting Facility to fund the collateral posting requirements for specified natural gas hedging transaction volumes. (See discussion below under “Liquidity Effects of Commodity Hedging and Trading Activities.”)

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

The Oncor Revolving Credit Facility is used for working capital and other general corporate purposes. Oncor may increase the commitments under its facility in any amount up to $500 million, subject to the satisfaction of certain conditions. Availability increased $930 million from year-end 2007 to October 31, 2008 due to repayments made under such facility from the proceeds of the issuance of $1.500 billion principal amount of fixed-rate senior notes as described in Note 7 to the September 30, 2008 Financial Statements. As of October 31, 2008, Oncor held cash and cash equivalents totaling $241 million.

See Note 17 to the 2007 year-end Financial Statements and Note 7 to the September 30, 2008 Financial Statements for additional discussion of the facilities.

Bankruptcy Filing of Lehman Brothers Holdings Inc.—In September 2008, Lehman Brothers Holdings Inc. (Lehman) filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code. EFH Corp. and its subsidiaries have business relationships with Lehman and its subsidiaries.

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

A subsidiary of Lehman that filed for bankruptcy under the U.S. Bankruptcy Code in October 2008 is a lender under the TCEH Senior Secured Facilities. The aggregate amount of unfunded commitments under the TCEH Delayed Draw Term Loan Facility as of October 31, 2008 was approximately $842 million, which amount includes approximately $14 million of availability attributable to the Lehman subsidiary’s aggregate funding commitment but

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excludes approximately $2 million of draw requests by TCEH that have not been funded by the Lehman subsidiary as of October 31, 2008. In addition, as of October 31, 2008, TCEH had outstanding cash borrowings under its Revolving Credit Facility of approximately $1.481 billion in the aggregate, including approximately $139 million funded by the Lehman subsidiary, and outstanding letters of credit under its Revolving Credit Facility of approximately $18 million in the aggregate, of which approximately $2 million was for the account of the Lehman subsidiary. The aggregate amount of unfunded commitments under the TCEH Revolving Credit Facility as of October 31, 2008, was approximately $1.166 billion, which amount includes approximately $134 million of availability attributable to the Lehman subsidiary’s aggregate funding commitment but excludes approximately $35 million of draw requests by TCEH that have not been funded by the Lehman subsidiary as of October 31, 2008. Also as of October 31, 2008, Oncor had outstanding cash borrowings under its Revolving Credit Facility of $333 million in the aggregate, including approximately $13 million funded by the Lehman subsidiary. The aggregate amount of unfunded commitments under the Oncor Revolving Credit Facility as of October 31, 2008, was approximately $1.650 billion, of which the Lehman subsidiary’s unfunded portion was approximately $142 million. EFH Corp. does not believe the potential reduction in available capacity under these credit facilities will have a significant impact on its liquidity or the liquidity of its subsidiaries.

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

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

As a result, on October 31, 2008, EFH Corp. delivered notice to The Bank of New York, in its capacity as trustee under the indenture for the toggle notes, that, with respect to the cash interest that would have been due on such notes on the May 1, 2009 interest payment date in the amount of approximately $141 million, EFH Corp. will make such interest payment by using the PIK feature of the toggle notes instead of cash. The election will increase the interest rate on the toggle notes from 11.25% to 12.00% during the interest period covered by the PIK election and require EFH Corp. to issue an additional $150 million principal amount of toggle notes on May 1, 2009. In addition, the election will increase liquidity by an amount equal to approximately $141 million, constituting the amount of cash interest that otherwise would have been payable on May 1, 2009, and increase the expected annual cash interest expense by approximately $17 million, constituting the additional cash interest that would be payable with respect to the $150 million of additional toggle notes.

Similarly, on October 31, 2008, TCEH delivered notice to The Bank of New York, in its capacity as trustee under the indenture for the TCEH toggle notes, that, with respect to the cash interest that would have been due on such notes on the May 1, 2009 interest payment date in the amount of approximately $92 million, TCEH will make such interest payment by using the PIK feature of the TCEH toggle notes instead of paying cash. The election will increase the interest rate on the TCEH toggle notes from 10.50% to 11.25% during the interest period covered by the PIK election and require TCEH to issue an additional approximately $98.5 million principal amount of TCEH toggle notes on May 1, 2009. In addition, the election will increase liquidity by an amount equal to approximately $92 million, constituting the amount of cash interest that otherwise would have

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been payable on May 1, 2009, and increase the expected annual cash interest expense by approximately $10 million, constituting the additional cash interest that would be payable with respect to the approximately $98.5 million of additional TCEH toggle notes.

Liquidity Needs, Including Capital Expenditures—Capital expenditures, including capitalized interest, for 2008 are expected to total approximately $3.1 billion and include:

• $900 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 at Oak Grove;

• approximately $700 million for major maintenance, 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 7 to the September 30, 2008 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.

Additional Financial Market Uncertainty Considerations—EFH Corp. has evaluated its investments held in trusts, including those that will be used by EFH Corp. to satisfy future obligations under pension and postretirement benefit plans. The recent substantial dislocation in the financial markets has caused a significant decline in the value of such investments, and a continuation or further dislocation in the markets could be material to EFH Corp. While the pension and postretirement plan investments include some subprime-related securities, a decline in the fair value of such investments is not expected to be material.

As of September 30, 2008, EFH Corp. and its subsidiaries had no debt that was insured. TCEH had $204 million of tax-exempt long-term debt backed by $208 million in letters of credit expiring in 2014. If there is a loss of confidence in the creditworthiness of the letter of credit provider and TCEH were consequently unable to substitute letters of credit from an acceptable bank, TCEH could experience an increase in its interest expense.

Pension 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. Contributions to the pension plan in 2007 totaled $4 million. EFH Corp. expects to make required contributions of $22 million to its pension plan in the fourth quarter of 2008. EFH Corp. made required pension contributions of $7 million, $18 million, $18 million and $95 million in January, April, July and September of 2008, respectively. As of October 23, 2008, required pension plan calendar year funding for EFH Corp. was expected to total $59.1 million in 2009.

Liquidity Effects of Commodity Hedging and Trading Activities—Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. EFH Corp. and its subsidiaries use cash and letters of credit and other collateral structures to satisfy such collateral obligations. In addition, TCEH’s Commodity Collateral Posting Facility, an uncapped senior secured revolving

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credit facility, funds the cash collateral posting requirements 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. The aggregate principal amount of this facility is determined by the exposure arising from higher forward market prices, regardless of the amount of such exposure, on a portfolio of certain natural gas hedging transaction volumes. Including those hedging transactions where margin deposits are covered by unlimited borrowings under the TCEH Commodity Collateral Posting Facility, at October 24, 2008, more than 95% of EFH Corp.’s long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in EFH Corp.’s liquidity exposure associated with collateral requirements for those hedging transactions. See Note 17 to the 2007 year-end Financial Statements and Note 7 to the September 30, 2008 Financial Statements for more information about this facility.

As of September 30, 2008, subsidiaries of EFH Corp. have received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $302 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $79 million posted as of December 31, 2007,

• $464 million in cash has been posted with counterparties for over-the-counter and other non-exchanged cleared transactions, as compared to $429 million posted as of December 31, 2007, and

• $829 million in letters of credit have been posted with counterparties, as compared to $592 million posted as of December 31, 2007.

Borrowings under the TCEH Commodity Collateral Posting Facility funded the substantial majority of the above cash postings. The posted letters of credit were largely supported by restricted cash borrowed under the TCEH Letter of Credit Facility. See Notes 17 and 18 to the 2007 year-end Financial Statements and Notes 7 and 8 to the September 30, 2008 Financial Statements.

With respect to exchange cleared transactions, these transactions typically require initial margin (i.e. the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variance margin (i.e. the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. With respect to cash collateral that is received, such cash collateral is either used by EFH Corp. and its subsidiaries for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or it is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. On over-the-counter transactions, such counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing EFH Corp.’s liquidity in the event that it was not restricted. As of September 30, 2008, cash collateral received totaled $20 million. See Note 15 to the September 30, 2008 Financial Statements regarding restricted cash.

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 October 24, 2008, for each $1.00 per MMBtu increase in forward natural gas prices across the period from 2008 through 2014, EFH Corp.’s cash collateral posting requirements associated with the long-term hedging program would increase by approximately $820 million, essentially all of which would be funded by the TCEH Commodity Collateral Posting Facility.

Distributions from Oncor—Until December 31, 2012, distributions paid by Oncor are limited to an amount not to exceed Oncor’s net income (determined in accordance with GAAP, subject to certain defined adjustments, including

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the $72 million ($46 million after-tax) one-time refund to customers in September 2008). See discussion above under “Significant Developments—Oncor Refund to Customers.” Distributions are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.

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

Income Tax Refunds/Payments—In September 2008, EFH Corp. received a $98 million refund related to 2007 tax payments in connection with the filing of its 2007 federal income tax return and expects an additional refund of $142 million by the end of 2008 as a result of filing for a net operating loss carryback to the 2006 tax year. Federal income tax payments totaled $271 million in 2007 and $220 million in 2006.

As discussed in Note 12 to the 2007 year-end 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. EFH Corp. expects that no material federal income tax payments will be made over the next twelve months.

Also see Note 15 to the September 30, 2008 Financial Statements under “Uncertain Tax Positions” for discussion of an anticipated $100 million income tax refund related to a 2006 claim.

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 $700 million, $363 million and $627 million at September 30, 2008, December 31, 2007 and December 31, 2006, respectively. See Note 16 to the 2007 year-end Financial Statements and Note 6 to the September 30, 2008 Financial Statements for a more complete description of the program including the impact of the program on the financial statements for the periods presented and the contingencies that could result in a reduction of funding available under the program.

Capitalization—The capitalization ratios of EFH Corp. consisted of 87.9% and 85.2% long-term debt, less amounts due currently, and 12.1% and 14.8% common stock equity, at September 30, 2008 and December 31, 2007, respectively. Total debt to capitalization, including short-term debt, was 88.6%, 85.9% and 85.5% at September 30, 2008, December 31, 2007 and December 31, 2006, respectively.

Covenants and Restrictions under Financing Arrangements—Each of the TCEH Senior Secured Facilities and indentures governing the TCEH Notes and the 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 the 2007 year-end Financial Statements and Note 7 to the September 30, 2008 Financial Statements for additional discussion of the covenants contained in these financing arrangements. Certain series of TCEH’s pollution control revenue bonds, which were remarketed in June 2008, include covenants similar to those discussed below regarding the TCEH Notes.

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When the term “Adjusted EBITDA” (see Glossary) is referenced in the covenant description below, it is a reference to, and generally synonymous with, the term “Consolidated EBITDA” that is used in the TCEH Senior Secured Facilities and a reference to, and generally synonymous with, the term “EBITDA” that is used in the indentures governing the notes. Further, the indenture provides that Oncor results be included in Adjusted EBITDA when used in connection with making restricted payments and investments other than payments to the Sponsor Group, but that the Oncor results be excluded and distributions received from Oncor be included when used in connection with incurrences of indebtedness. Adjusted EBITDA (as used in the restricted payments covenant contained in the indentures governing the notes) for the twelve months ended September 30, 2008 totaled $4.8 billion for EFH Corp. The following is a reconciliation of net income to Adjusted EBITDA:

	Twelve Months Ended September 30, 2008
Net income (loss)	$	(2,235	)
Income tax expense (benefit)		(1,038	)
Interest expense and related charges		3,371
Depreciation and amortization		1,654
EBITDA	$	1,752
Oncor EBITDA		(1,384	)
Oncor distributions/dividends		288
Interest income		(49	)
Amortization of nuclear fuel		74
Purchase accounting adjustments (a)		463
Impairment of assets and inventory write down (b)		457
Unrealized net (gain) or loss resulting from hedging transactions		1,796
Losses on sale of receivables		33
Income from discontinued operations, net of tax effect		(1	)
Noncash compensation expenses (SFAS 123R) (c)		23
Severance expense (d)		1
Transition and business optimization costs (e)		47
Transaction and merger expenses (f)		107
Restructuring and other (g)		33
Expenses incurred to upgrade or expand a generation station (h)		100
Adjusted EBITDA per Incurrence Covenant	$	3,740
Add back Oncor Adjustments	$	1,060
Adjusted EBITDA per Restricted Payments Covenants	$	4,800

(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits not recognized in net income due to purchase accounting.

(b) Impairment of assets includes impairment of emission allowances intangible assets and charges related to the impairment of the assets and transportation and storage of materials related to cancelled development of coal-fueled generation facilities.

(c) Noncash compensation expenses exclude capitalized amounts.

(d) Severance expense includes amounts incurred related to outsourcing, restructuring and other amounts deemed to be in excess of normal recurring amounts.

(e) Transition and business optimization costs include professional fees primarily for retail billing and customer care systems enhancements and incentive compensation.

(f) Transaction and merger expenses include costs related to the Merger, abandoned strategic transactions and a terminated joint venture. Also include administrative costs related to the cancelled program to develop coal-fueled generation facilities, the Sponsor management fee and costs related to certain growth initiatives.

(g) Restructuring and other for the 2008 periods include a litigation accrual and the charge related to the bankruptcy of a subsidiary of Lehman Brothers Holdings Inc., and for the 2007 periods includes credits related to impaired combustion turbine leases and other restructuring initiatives and nonrecurring activities.

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

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Maintenance Covenant—Under the TCEH Senior Secured Facilities, TCEH and its restricted subsidiaries are required to maintain a consolidated secured debt to Adjusted EBITDA ratio (as defined in the TCEH Senior Secured Facilities) measured over a rolling four-quarter measurement period, which 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. The ratio for the period ending September 30, 2008 was 4.59 to 1.00.

Debt Incurrence Covenants—Under the indenture governing the notes, EFH Corp. and its restricted subsidiaries (other than TCEH and its restricted subsidiaries) are not permitted to incur indebtedness or issue certain classes of preferred stock unless, on a pro forma basis, after giving effect to such incurrence or issuance, the fixed charge coverage ratio (as defined in the indenture) on a consolidated basis for EFH Corp. and its restricted subsidiaries is at least 2.0 to 1.0 or such incurrence or issuance is otherwise permitted by specified exceptions in the indenture. The fixed charge coverage ratio is generally defined as the ratio of Adjusted EBITDA of EFH Corp. to fixed charges of EFH Corp., in each case on a consolidated basis but excluding Oncor. The fixed charge coverage ratio for EFH Corp. was 1.2 to 1.0 at September 30, 2008. In addition, under this indenture, TCEH and its restricted subsidiaries are not permitted to incur indebtedness or issue certain classes of preferred stock unless, on a pro forma basis, after giving effect to such incurrence or issuance, the fixed charge coverage ratio (as defined in the indenture) on a consolidated basis for TCEH and its restricted subsidiaries is at least 2.0 to 1.0 or such incurrence or issuance is otherwise permitted by specified exceptions in the indenture. The fixed charge coverage ratio for that purpose is generally defined as the ratio of Adjusted EBITDA of TCEH to fixed charges of TCEH, in each case, on a consolidated basis. The fixed charge coverage ratio for TCEH as of September 30, 2008 was 1.4 to 1.0.

Under the TCEH Senior Secured Facilities, TCEH and its restricted subsidiaries are generally not permitted to incur indebtedness unless, on a pro forma basis, after giving effect to such incurrence, the Adjusted EBITDA to consolidated interest expense ratio (as defined in the TCEH Senior Secured Facilities) is at least 2.0 to 1.0 or such incurrence is otherwise permitted by specified exceptions in the TCEH Senior Secured Facilities. This ratio was 1.4 to 1.0 for the twelve months ended September 30, 2008.

Under the indenture governing the TCEH Notes, TCEH and its restricted subsidiaries are not permitted to incur indebtedness or issue certain classes of preferred stock unless, on a pro forma basis, after giving effect to such incurrence or issuance, the fixed charge coverage ratio (as defined in such indenture) on a consolidated basis for TCEH and its restricted subsidiaries is at least 2.0 to 1.0 or such incurrence or issuance is otherwise permitted by specified exceptions in such indenture. The fixed charge coverage ratio is generally defined as the ratio of Adjusted EBITDA of TCEH to fixed charges of TCEH, in each case, on a consolidated basis. The ratio was 1.4 to 1.0 for the twelve months ended September 30, 2008.

Restricted Payments/Limitation on Investments—Under the indenture governing the notes, EFH Corp. and its restricted subsidiaries have limitations, subject to certain exceptions, on making restricted payments (as defined in the indenture), including cash dividends, equity repurchases, subordinated debt repayments and investments, unless the amount of such restricted payments is less than a formula based on 50% of consolidated net income (as defined in such indenture) and unless a fixed charge coverage ratio (as defined in such indenture), on a pro forma basis, after giving effect to such restricted payment, is at least 2.0 to 1.0 (or 2.0 to 1.0 of TCEH in the case of certain restricted payments by TCEH and its restricted subsidiaries) or as such restricted payment is otherwise permitted by specified exceptions in the indenture. The fixed charge coverage ratio for this purpose is generally defined as the fixed charge coverage ratio of EFH Corp. and all of its restricted subsidiaries, including Oncor Holdings and its subsidiaries as restricted subsidiaries for purposes of such calculation and was 1.4 to 1.0 for EFH Corp. as of September 30, 2008. However, in the case of payments to the Sponsor Group, the fixed charge coverage ratio for this purpose is defined as the fixed charge coverage ratio of EFH Corp. and its restricted subsidiaries (but not including Oncor Holdings and its subsidiaries as restricted subsidiaries for purposes of such calculation) and was 1.2 to 1.0 as of September 30, 2008. Notwithstanding any other provisions of the indenture, EFH Corp. and its restricted subsidiaries may not pay any dividends or other returns to Texas Holdings unless, on a pro forma basis, after giving effect to such payment, the

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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 and was 9.2 to 1.0 as of September 30, 2008.

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

Financial Covenants, Credit Rating Provisions and Cross Default Provisions—The terms of certain financing arrangements of subsidiaries of EFH Corp. contain financial covenants that require maintenance of leverage ratios and/or contain minimum net worth covenants. As of September 30, 2008, 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 November 3, 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+ and BBB- by S&P and Fitch, respectively.

Additionally, the rating agencies assign credit ratings on certain debt securities issued by EFH Corp. and its subsidiaries. The credit ratings assigned for debt securities issued by EFH Corp. and certain of its subsidiaries as of November 3, 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+	Baa3	BBB
Oncor (Senior Unsecured)	BBB+	Baa3	BBB-

(a) EFH Corp. cash-pay notes and toggle notes

(b) TCEH cash-pay notes and TCEH toggle notes

S&P and Fitch have placed the ratings for EFH Corp. and its subsidiaries on “stable outlook.” On November 3, 2008, Moody’s announced that it changed the rating outlook for EFH Corp. and TCEH to negative from stable, stating that the change was primarily related to the decision to elect the PIK interest option on the toggle notes and the TCEH toggle notes for the interest due on May 1, 2009. Moody’s ratings outlook for Oncor is not affected by this action and remains stable.

On November 5, 2008, Oncor sold a 19.75% minority stake to an investor group to further enhance Oncor’s separation from Texas Holdings, EFH Corp. and EFH Corp.’s other subsidiaries. In connection with Oncor’s execution of the agreement, S&P upgraded Oncor’s issuer credit rating and Oncor’s long-term debt ratings by two notches from BBB- to BBB+, and Moody’s upgraded Oncor’s long-term debt ratings by one notch from Ba1 to Baa3. Simultaneous with the Moody’s upgrade, Moody’s withdrew its issuer credit rating of Ba1 previously assigned to Oncor. As a matter of practice, Moody’s does not assign issuer credit ratings for investment grade utility companies. See Note 16 to the September 30, 2008 Financial Statements for additional information on the minority interest sale.

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

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Material Credit Rating Covenants and Credit Worthiness Effects on Liquidity—As a result of TCEH’s non-investment grade credit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, as of September 30, 2008 counterparties to those contracts could have required TCEH to post up to an aggregate of $100 million in additional collateral. This amount largely represents the below market terms of these contracts as of September 30, 2008; thus, this amount will vary depending on the value of these contracts on any given day.

Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of the previous downgrade of TCEH’s credit rating to below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. Based on requests to post collateral support from utilities that have been received by TCEH and its subsidiaries as of September 30, 2008, TCEH has posted collateral support in the form of letters of credit 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 September 30, 2008, the amount of customer deposits received from customers held by TCEH’s REP subsidiaries totaled approximately $120 million.

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

ERCOT also has rules in place to assure adequate credit worthiness of parties that schedule power on the ERCOT System. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $77 million as of September 30, 2008 (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 is required to post a letter of credit in an amount equal to $170 million to secure TXU Energy’s payment obligations to Oncor if two or more of Oncor’s credit ratings are below investment grade.

Other arrangements of EFH Corp. and its subsidiaries, including Oncor’s credit facility, the accounts receivable securitization program (see Note 16 to the 2007 year-end Financial Statements and Note 6 to the September 30, 2008 Financial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the credit ratings of certain EFH Corp. subsidiaries.

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

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

A default by TCEH or any restricted subsidiary in respect of indebtedness, excluding indebtedness relating to the sale of receivables program, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities such a default may cause the maturity of outstanding balances ($22.651 billion at October 31, 2008) under such facility to be accelerated.

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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 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 notes.

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

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

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

In the event of a default by TCEH relating to indebtedness in an amount equal to or greater than $200 million that results in the acceleration of such debt, then each counterparty under TCEH’s interest rate swap agreements with a notional value totaling $27.595 billion at October 31, 2008 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 ($333 million at October 31, 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.

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 the 2007 year-end 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

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(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 the 2007 year-end 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 the 2007 year-end 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 the 2007 year-end Financial Statements;

• employment contracts with management, and

• liabilities related to uncertain tax positions discussed in Note 12 to the 2007 year-end Financial Statements.

Guarantees—See Note 18 to the 2007 year-end Financial Statements for details of guarantees.

Off Balance Sheet Arrangements

See discussion above under “Sale of Accounts Receivable” and in Note 16 to the 2007 year-end Financial Statements and Note 6 to the September 30, 2008 Financial Statements.

Also see Note 18 to the 2007 year-end Financial Statements and Note 8 to the September 30, 2008 Financial Statements regarding guarantees.

Commitments and Contingencies

See Note 18 to the 2007 year-end Financial Statements and Note 8 to the September 30, 2008 Financial Statements for discussion of commitments and contingencies.

Changes in Accounting Standards

See Notes 1, 12, 22 and 24 to the 2007 year-end Financial Statements and Note 1 to the September 30, 2008 Financial Statements for a discussion of changes in accounting standards.

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Quantitative and Qualitative Disclosures About Market Risk

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

Risk Oversight

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

EFH Corp. has a corporate risk management organization that is headed by a Chief Risk Officer. The Chief Risk Officer, through his designees, enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits and evaluates the risks inherent in the various businesses of EFH Corp. and their associated transactions.

Commodity Price Risk

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

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

Long-Term Hedging Program—See 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.

	Nine Months Ended September 30, 2008		Year Ended December 31, 2007		Year Ended December 31, 2006
Month-end average Trading VaR:	$	7	$	9	$	12
Month-end high Trading VaR:	$	15	$	14	$	30
Month-end low Trading VaR:	$	3	$	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.

	Nine Months Ended September 30, 2008		Year Ended December 31, 2007		Year Ended December 31, 2006
Month-end average MtM VaR:	$	2,249	$	1,081	$	149
Month-end high MtM VaR:	$	3,549	$	1,576	$	391
Month-end low MtM VaR:	$	1,087	$	322	$	5

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

	Nine Months Ended September 30, 2008		Year Ended December 31, 2007		Year Ended December 31, 2006
Month-end average EaR:	$	2,260	$	1,070	$	156
Month-end high EaR:	$	3,916	$	1,559	$	387
Month-end low EaR:	$	1,069	$	318	$	21

The increases in the risk measures (MtM VaR and EaR) above were driven by higher natural gas prices and significant increases in market volatility.

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Interest Rate Risk

The table below provides information concerning EFH Corp.’s financial instruments as of December 31, 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 the 2007 year-end Financial Statements for a discussion of changes in debt obligations.

	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 the 2007 year-end 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 September 30, 2008, the potential reduction of annual pretax earnings due to a one-point increase in interest rates on long-term debt totaled approximately $36 million, taking into account the interest rate swaps discussed in Note 7 to the September 30, 2008 Financial Statements. See “Significant Developments—Interest Rate Swap Transactions” above for a discussion of interest rate swaps transacted in October 2008.

Credit Risk

Credit Risk—Credit risk relates to the risk of loss associated with nonperformance by counterparties. EFH Corp. and its subsidiaries maintain credit risk policies with regard to their counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty’s financial condition, credit rating and other quantitative and qualitative credit criteria and specify authorized risk mitigation tools including, but not limited to, use of standardized master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. EFH Corp. has processes for monitoring and managing credit exposure of its businesses including methodologies to analyze counterparties’ financial strength,

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measurement of current and potential future exposures and contract language that provides rights for netting and set-off. Credit enhancements such as parental guarantees, letters of credit, surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to assess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering into an agreement with a counterparty that creates exposure. Additionally, EFH Corp. has established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material adverse changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. This process can result in the subsequent reduction of the credit limit or a request for additional financial assurances.

Credit Exposure—EFH Corp.’s gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions arising from hedging and trading activities totaled $1.391 billion at September 30, 2008. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of September 30, 2008 include $853 million in accounts receivable from the retail sale of electricity to residential and business customers. As of September 30, 2008, EFH Corp. had cash deposits of $111 million as collateral for these receivables. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.

Most of the remaining credit exposure is with wholesale counterparties. These counterparties include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. As of September 30, 2008, the exposure to credit risk from the wholesale customers and counterparties totaled $317 million taking into account standardized master netting contracts and agreements described above but before taking into account $32 million in credit collateral (cash, letters of credit and other security interests) held by EFH Corp. subsidiaries.

Of this $285 million net exposure, 57% is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and EFH Corp.’s internal credit evaluation process. Those customers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. EFH Corp. routinely monitors and manages its credit exposure to these customers and counterparties on this basis. See discussion above under “Bankruptcy Filing of Lehman Brothers Holdings Inc.”

In addition, Oncor has exposure to credit risk totaling $221 million at September 30, 2008, of which $193 million represents potential nonperformance by nonaffiliated REPs. This exposure consists almost entirely of noninvestment grade trade accounts receivable. Oncor has one customer that represents more than 10% of the nonaffiliated trade accounts receivable at September 30, 2008. That customer represents 12% of the net exposure.

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The following table presents the distribution of credit exposure as of September 30, 2008, for wholesale counterparties. This credit exposure represents wholesale trade accounts receivable and net asset positions on the balance sheet arising from hedging and trading activities by investment grade and noninvestment grade, credit quality and maturity after taking into consideration netting within each contract and any master netting contracts with counterparties. The amounts below do not include asset liens held as security for a portion of the net exposure.

Successor
	Exposure before Credit Collateral			Credit Collateral		Net Exposure			Net Exposure by Maturity
									2 years or less		Between 2-5 years			Greater than 5 years		Total
Investment grade	$	169		$	7	$	162		$	164	$	(69	)	$	67	$	162
Noninvestment grade		148			25		123			120		3			—		123
Totals	$	317		$	32	$	285		$	284	$	(66	)	$	67	$	285
Investment grade		53	%				57	%
Noninvestment grade		47	%				43	%

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

EFH Corp. does not anticipate any material adverse effect on its financial position or results of operations due to nonperformance by any customer or counterparty.

EFH Corp.’s subsidiaries had credit exposure to three counterparties each having an exposure greater than 10% of the net $285 million credit exposure. These three counterparties represented 17%, 13%, and 11%, respectively, of the net exposure. EFH Corp. views exposure to these counterparties to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating, collateral postings or business relationship with EFH Corp. However, this concentration increases the risk that a default would have a material effect on EFH Corp.’s net income and cash flows.

With respect to credit risk related to the long-term hedging program, over 91% of the transaction volumes are with counterparties with an A credit rating or better. Additionally, EFH Corp. has potential credit concentration risk related to the limited number of counterparties in the program. The 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 taken as a whole.

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

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OUR BUSINESSES

General

We are a Dallas-based energy company that manages a portfolio of competitive and regulated energy businesses in Texas. We are a holding company conducting our operations principally through our subsidiaries, TCEH and Oncor.

TCEH is a holding company for businesses 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.

As of September 30, 2008, 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 U.S. Luminant is currently constructing three lignite/coal-fueled generation units in Texas with expected generation capacity totaling approximately 2,200 MW. Permits have been obtained for construction of the three units, which are expected to come on-line in 2009 and 2010. TXU Energy provides competitive electricity and related services to approximately 2.2 million retail electricity customers in Texas. As of September 30, 2008, TXU Energy’s estimated share of the total ERCOT retail market for residential and business market electricity customers was approximately 37% and 26%, respectively (based on customer counts).

Oncor is engaged in regulated electricity transmission and distribution operations in Texas that are primarily regulated by the PUCT. 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. A significant portion of Oncor’s revenues represent fees for delivery services provided to TCEH. Distribution revenues from TCEH represented 40% of Oncor’s total revenues for the nine months ended September 30, 2008 and 41% of Oncor’s total revenues for the year ended December 31, 2007.

Upon the consummation of the Merger, EFH Corp. and Oncor 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 “The Transactions—Ring-Fencing” for a description of the material terms of the ring-fencing measures.

At September 30, 2008, we had approximately 8,000 full-time employees, including approximately 2,600 employees under collective bargaining agreements.

Our Market

We operate 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 generators, power marketers, transmission service providers, distribution service providers, REPs and consumers.

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,

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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 U.S. over the same period. For 2007, hourly demand peaked at 62,188 MW. The ERCOT market has limited interconnections to other markets in the U.S., 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 1996, over 34,000 MW of mostly natural gas-fueled and wind generation capacity has been developed in the ERCOT market. Net generation capacity in the ERCOT market for 2008 totals approximately 72,820 MW, excluding mothballed capacity; approximately 65% of this capacity is natural gas-fueled generation and approximately 27% of this capacity consists of lignite/coal and nuclear-fueled baseload generation. ERCOT currently has a target reserve margin level of approximately 12.5%; the reserve margin is projected by ERCOT to be 15.8% in 2009, 21.2% in 2010, and drop to 15.8% by 2014.

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 2007. 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 in ERCOT 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 zone, with the Sandow unit in the South zone.

The ERCOT market operates under reliability standards set by the NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure adequacy and reliability of power supply across Texas’s main interconnected transmission grid. The ERCOT independent system operator is responsible for maintaining reliable operations of the bulk electricity supply system in the 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 distribution service area. Oncor participates with the ERCOT independent system operator and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to meet reliability needs, increase bulk power transfer capability to remove existing constraints and interconnect generation on the ERCOT transmission grid.

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Our Strategies

Each of our 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 our strategy include:

• Increase value from existing businesses. Our strategy focuses on striving for top quartile or better performance across our operations in terms of reliability, cost and customer service. We will continue to focus on upgrading four critical skill sets: operational excellence across each business; market leadership and customer focus; 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 we implement these principles is a program called the “Luminant Operating System,” which is a program to drive ongoing productivity improvements in Luminant’s operations through application of lean operating techniques and deployment of a high-performance industrial culture.

• Pursue growth opportunities across business lines. We will selectively target growth opportunities in each of our business lines. Our scale in each of our operating businesses allows us 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. We 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 our performance over the near term but can enhance our growth profile over time. Specific growth initiatives for each business include:

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

• TXU Energy: Increase the number of customers served throughout the competitive ERCOT market areas by delivering superior value to customers through high quality customer service and innovative energy products, including pioneering energy efficiency initiatives and service offerings.

• Oncor: Invest in technology upgrades including advanced metering systems and construct new transmission and distribution facilities to meet the needs of the growing Texas market.

The growth initiatives at Oncor benefit from regulatory capital recovery mechanisms known as “capital trackers” that Oncor believes enable adequate and timely recovery of transmission investments and advanced metering investments through the rates charged by Oncor.

• Reduce the volatility of cash flows through a commodity risk management strategy. A key component of our risk management strategy is our 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 our exposure to natural gas prices. As of October 24, 2008, approximately 2.1 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 280,000 GWh at an

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assumed 7.5 MMBtu/MWh market heat rate) have been effectively sold forward over the period from 2008 to 2014, at average annual prices ranging from $7.20 per MMBtu to $8.35 per MMBtu. Taking into consideration the estimated portfolio impacts of our retail electricity business, these natural gas hedging transactions result in us having effectively hedged approximately 77% of our expected baseload generation natural gas price exposure (on an average basis for 2008 through 2014). 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 September 30, 2008, more than 95% of the hedging transactions were secured or supported by first-lien interests in TCEH’s assets and result in no direct liquidity exposure.

• Pursue new environmental initiatives. We are committed to continue to operate in compliance with all environmental laws, rules and regulations and to reduce our impact on the environment. We have formed a Sustainable Energy Advisory Board that advises us in our pursuit of technology development opportunities that reduce our impact on the environment while balancing the need to address the energy requirements of Texas. Our Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, customers, economic development in Texas and technology/reliability standards. In addition, we are focused on and are pursuing opportunities to reduce emissions from our 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. We expect Luminant to make these reductions through a combination of investment in new emission control equipment, new coal cleaning technologies and optimizing fuel blends. We also expect such investments to provide economic benefits by reducing future costs associated with complying with environmental emissions standards. In addition, we expect to 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: the Competitive Electric segment (primarily represented by TCEH) and the Regulated Delivery segment (primarily represented by Oncor). See Note 27 to the 2007 year-end Financial Statements and Note 14 to the September 30, 2008 Financial Statements.

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 Luminant (i.e., Luminant Power, Luminant Energy and Luminant Construction) and TXU Energy. The operations of Luminant Power, Luminant Energy and TXU Energy are conducted through separate legal entities.

Luminant Power—Luminant Power’s electricity generation fleet consists of 19 plants in Texas with total generating capacity as of September 30, 2008 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.

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(b) Includes 1,329 MW representing five units mothballed and not currently available for dispatch.

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

The generation plants are located primarily on land owned in fee. Nuclear and lignite/coal-fueled (baseload) plants are generally scheduled to run at capacity except for periods of scheduled maintenance activities or, in the case of lignite/coal units, backdown due to periods of low demand. The natural gas-fueled generation units supplement the baseload generation capacity in meeting 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 U.S. 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 all of its nuclear fuel conversion services through 2008 and 59% of its requirements through 2015. In addition, Luminant Power has contracts for the acquisition of all and 96% of its uranium requirements in 2008 and 2009, respectively, and for 94% of its nuclear fuel enrichment services through 2009, as well as all of its nuclear fuel fabrication services through 2018.

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

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 U.S. coal-fueled generation facilities.

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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 892 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 2,366 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 89% 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 7,899 MW of currently available capacity, 1,000 MW of capacity being operated for unaffiliated third parties, pursuant to the direction of the unaffiliated third parties, and 1,329 MW of capacity currently mothballed. 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 “Our 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.

Agreements have been executed with EPC contractors, Bechtel Power Corporation and Fluor Enterprises, Inc., to engineer and construct the units at Sandow and Oak Grove, respectively. Design and procurement activities for the three units are essentially complete and construction is well underway. Permits for the construction of all three units have been obtained. The expected commercial operation dates of the units are as follows: Sandow in 2009 and Oak Grove’s two units in 2009 and 2010. (See Note 18 to the 2007 year-end Financial Statements and Note 8 to the September 30, 2008 Financial Statements for additional information about the 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 all detailed cost and engineering studies for the additional environmental systems, and the cost estimates could change materially as Luminant Construction determines the details of and further evaluates the engineering and construction costs related to these investments.

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TXU Energy—TXU Energy serves approximately 2.2 million retail electricity customers in Texas. 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 all areas of the ERCOT market now open to competition, including the Dallas/Fort Worth, Houston, Corpus Christi, and lower Rio Grande Valley areas of Texas. TXU Energy continues to market its services in Texas to add new customers and to retain its existing customers. As of September 30, 2008, there are more than 130 active REPs certified to compete within the state of Texas.

TXU Energy’s strategy focuses on providing its customers with high quality customer service and creating new products and services to meet customer needs. 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 a wide range of residential products to meet various customer needs, currently more than any retailer in the ERCOT market. Starting in 2008, TXU Energy is investing $100 million over the next five years 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. TXU Energy has committed to provide price protection to these customers through December 2008. In addition, TXU Energy committed in 2006 to not increase prices above then current levels through 2009 for qualifying residential customers who remain on certain plans with rates that were then equal to the price-to-beat rate.

Regulation—Luminant Power is an exempt wholesale generator under the Energy Policy Act of 2005 and is subject to the jurisdiction of the NRC with respect to its nuclear generation plant. NRC regulations govern the granting of licenses for the construction and operation of nuclear-fueled generation plants and subject such plants to continuing review and regulation. Luminant Energy also holds a power marketer license from the FERC.

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. This territory 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. Most of Oncor’s power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way as permitted by law. Oncor’s transmission and distribution rates are regulated by the PUCT.

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

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 and information technology. Reflecting this commitment to infrastructure, in September 2008, Oncor, together with several other ERCOT utilities, filed with the PUCT a joint CREZ Transmission Plan, in which Oncor proposes to build at least 1,000 miles of transmission lines and facilities in and around Oncor’s service territory. Based on ERCOT’s estimates, this will require an investment of more than $2 billion by Oncor (see discussion under “Regulation and Rates-Oncor Matters with the PUCT-Competitive Renewable Energy Zones (CREZ)).

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

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

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.

As of December 31, 2007, Oncor’s transmission facilities included 4,873 circuit miles of 345-kV transmission lines and 9,789 circuit miles of 138-and 69-kV transmission lines. As of December 31, 2007, 52 generation plants totaling 33,794 MW were directly connected to Oncor’s transmission system, and 268 transmission stations and 708 distribution substations were served from Oncor’s transmission system.

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As of December 31, 2007, Oncor’s transmission facilities had 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.

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, grew an average of approximately 1.5% per year, adding approximately 45,000 points of delivery in 2007.

As of December 31, 2007, the Oncor distribution system consisted 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. As of September 30, 2008, Oncor’s distribution customers consisted of more than 70 REPs in Oncor’s certificated service area, including TCEH. Distribution revenues from TCEH represented 41% and 40% of Oncor’s total revenues for 2007 and for the nine months ended September 30, 2008, respectively. 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 it 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, EFH Corp. believes that Oncor is not a public utility as defined in the Federal Power Act and has been advised by its legal counsel that it is not subject to general regulation under this act.

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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 an order on rehearing entered in April 2008, Oncor filed a rate case with the PUCT (Docket No. 35717) in June 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.

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 U.S. Department of Energy. This initiative supports the Bush Administration’s greenhouse gas emissions intensity reduction program, Climate VISION. In addition, 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 U.S. energy and environmental policy should seek to ensure U.S. energy security and independence;

• Solutions should encourage investment in a diverse supply of new generation to meet U.S. 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

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• 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 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, and its total wind power portfolio is now 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 beginning in 2008 its subsidiaries will invest $400 million over five years in programs designed to encourage customer electricity demand efficiencies representing $200 million more than amounts planned to be invested prior to the Merger, as part of normal 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 has filed an application 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.

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 U.S. Congress and, in April 2007, the U.S. 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 U.S. 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 these 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 were required to be phased in

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between 2009 and 2015, were 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 were required to have allowances for each ton emitted, and emitters were allowed to trade emissions under the cap. Luminant received its NO_x allowances under CAIR for the years 2009 through 2014. In July 2008, the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit) vacated CAIR. It is uncertain at this time what the final outcome of the D.C. Circuit’s decision will be, including whether the D.C. Circuit will grant the EPA’s request for rehearing or revise its decision to allow CAIR to remain in place during any court-ordered revision of CAIR by the EPA or what actions the TCEQ or other entities might take.

In 2005, the EPA also published a final rule requiring reductions of mercury emissions from coal-fueled generation plants. The Clean Air Mercury Rule (CAMR) was based on a nationwide cap and trade approach. The mercury reductions were required to be phased in between 2010 and 2018. In March 2008, the D.C. Circuit vacated the CAMR. Depending on the outcome of any appeals to the U.S. Supreme Court, CAMR could be reinstated. If appeals are unsuccessful, the EPA must begin development of rules implementing a Maximum Achievable Control Technology standard, which will likely take several years. See “Our Businesses-Legal and Administrative Proceedings-Litigation Related to Generation Development”.

SO₂ reductions required under the proposed regional haze/visibility rule (or so-called BART rule) only apply to units built between 1962 and 1977. The reductions 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. The D.C. Circuit decision to vacate CAIR may now require further analysis and rulemaking by Texas.

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 applicable environmental rules to provide the most cost-effective compliance plan options.

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.

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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 new regulations, if any, that replace them.

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

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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.

Legal and Administrative Proceedings

Litigation Related to the Merger

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

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

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

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directors filed a Motion to Dismiss and in May 2007, the Court granted the Motion and dismissed the consolidated putative class action suit with prejudice. In May 2007, Plaintiffs moved for reconsideration of the order dismissing the action; however, Plaintiffs subsequently withdrew this motion. As described below, these lawsuits were dismissed in April 2008.

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

In July 2007, the Sponsor Group, joined by EFH Corp. for the limited purpose described below, executed a memorandum of understanding with the plaintiffs in certain of the lawsuits described above pursuant to which, when approved by the court in which the litigation was pending, to the extent required, all of the litigation related to the Merger described above would 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 related to the approval of the Merger as part of the agreement between the Sponsor Group and the plaintiffs to settle the litigation and agreed that under certain circumstances the termination fee payable by EFH Corp. under the Merger Agreement would be $925 million rather than $1 billion. In addition, by reasons of the closing of the Merger, EFH Corp. merged with the entity obligated to fund any court approved attorneys’ fees. Accordingly, EFH Corp. was legally obligated for such payment. In January 2008, a final settlement agreement was executed by the plaintiffs in the above described litigation matters related to the Merger. The defendants and the courts with jurisdiction over the litigation considered the settlement for approval in April 2008. The settlement was approved and a Final Order and Judgment was entered dismissing with prejudice all litigation pending in the State District Court. The settlement was approved and a Final Order and Judgment was entered into by the U.S. District Court, in May 2008, dismissing with prejudice all claims related to the Merger against EFH Corp. and its preclosing officers and directors. In June 2008, an objector appealed the Final Order and Judgment of the U.S. District Court to the U.S. Court of Appeals for the Fifth Circuit. In November 2008, the appeal was denied.

Litigation Related to Generation Development

An administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas to a subsidiary of EFH Corp. was filed in September 2007 in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments; and remand the matter back to the TCEQ for further proceedings. The TCEQ has filed the administrative record with the District Court. No further activity has occurred in the appeal. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. 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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In December 2006, a lawsuit was filed in the U.S. District Court for the Western District of Texas against Luminant Generation Company LLC (then known as TXU Generation Company LP), Oak Grove Management Company LLC (both indirect wholly-owned subsidiaries of EFH Corp.) and EFH Corp. (then known as TXU Corp.). The complaint sought declaratory and injunctive relief, as well as the assessment of civil penalties, with respect to the permit application for the construction and operation of the Oak Grove generation facility in Robertson County, Texas. The plaintiffs alleged violations of the Federal Clean Air Act, Texas Health and Safety Code and Texas Administrative Code and sought to temporarily and permanently enjoin the construction and operation of the Oak Grove generation plant. The complaint also asserted that the permit application was deficient in failing to comply with various modeling and analyses requirements relative to the impact of emissions from the Oak Grove plant. Plaintiffs further requested that the District Court enter an order requiring the defendants to take other appropriate actions to remedy, mitigate and offset alleged harm to the public health and environment. EFH Corp. believes the Oak Grove air permit granted by the TCEQ in June 2007 is protective of the environment and that the application for and the processing of the air permit by Oak Grove Management Company LLC with the TCEQ has been in accordance with applicable law. EFH Corp. and the other defendants filed a Motion to Dismiss the litigation, which was granted by the District Court in May 2007. The plaintiffs appealed the District Court’s dismissal of the case to the U.S. Fifth Circuit Court of Appeals, and in July 2008, the U.S. Fifth Circuit Court of Appeals upheld the District Court’s dismissal of the case. The plaintiffs appealed that decision by the U.S. Fifth Circuit Court of Appeals to the U.S. Supreme Court, and on December 1, 2008, the U.S. Supreme Court denied the plaintiffs petition for review. Accordingly, this litigation has concluded favorably to EFH Corp.

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

In September 2007, a subsidiary of EFH Corp. acquired from Alcoa Inc. the air permit related to the Sandow 5 facility that had been previously issued by the TCEQ. Although a federal district court approved a settlement pursuant to which EFH Corp. acquired the permit, environmental groups opposed to the settlement appealed the district court’s decision to the U.S. Fifth Circuit Court of Appeals. In June 2008, the U.S. Fifth Circuit Court of Appeals upheld the district court’s decision. The time period for the environmental groups to petition the U.S. Supreme Court for review has elapsed, and EFH Corp. is not aware of any such petition having been filed.

Other Litigation

In September 2005, a lawsuit was filed in the U.S. District Court for the Northern District of Texas, Dallas Division against EFH Corp. (then known as TXU Corp.) and C. John Wilder, EFH Corp.’s former Chief Executive Officer. The plaintiffs’ Amended Complaint asserts claims on behalf of the plaintiffs and a putative class of owners of certain EFH Corp. securities who tendered such securities in connection with a tender offer conducted by EFH Corp. in 2004. The Amended Complaint alleges violations of the provisions of Sections 14(e), 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 thereunder. The allegations relate to a tender offer conducted in September and October 2004 for certain equity-linked securities in which it was expressly disclosed that EFH Corp. management was evaluating whether it should recommend to the board of directors that the board reevaluate EFH Corp.’s dividend policy. After the tender offer was closed, and consistent with the disclosure, management did make a recommendation to the board to reevaluate the dividend policy and the board elected to increase the quarterly dividend. The plaintiffs contend that such disclosure in connection with the tender offer was inadequate. EFH Corp. maintains that the disclosure provided in connection

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with the tender offer regarding the evaluation of the dividend policy was complete and accurate at the time the tender offer was initiated as well as when it was closed. A Motion to Dismiss was filed by the defendants, and the District Court entered an order granting the Motion to Dismiss and dismissing this litigation with prejudice in August 2006. The plaintiffs filed a timely notice of appeal, and on appeal, the U.S. Court of Appeals for the Fifth Circuit remanded the dismissal to the District Court in light of the decisions in Tellabs, Inc. v. Makor Issues & Rights, Ltd. On remand, plaintiffs filed a Second Amended Complaint, and defendants filed a Motion to Dismiss. The District Court entered an order granting the Motion to Dismiss and dismissing this litigation with prejudice in April 2008. The plaintiffs filed a timely notice of appeal in May 2008 and the appeal is currently pending before the U.S. Court of Appeals for the Fifth Circuit. Briefing on the appeal has been completed. While EFH Corp. is unable to estimate any possible loss or predict the outcome of this litigation, EFH Corp. believes the claims made in this litigation are without merit and, accordingly, intends to vigorously defend the appeal.

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

Regulatory Investigations and Reviews

In March 2007, the PUCT issued a Notice of Violation (NOV) stating that the PUCT Staff was recommending an enforcement action, including the assessment of administrative penalties, against EFH Corp. and certain affiliates for alleged market power abuse by its power generation affiliates and Luminant Energy in ERCOT-administered balancing energy auctions during certain periods of the summer of 2005. In September 2007, the PUCT issued a revised NOV in which the proposed administrative penalty amount was reduced from $210 million to $171 million. The revised NOV was necessary, according to the PUCT Staff, to correct calculation errors in the initial NOV. As revised, the NOV 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. In March 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. In April 2008, PUCT Staff submitted its cross-motion on the same issue. In July 2008, the administrative law judges issued their order on the cross-motions for summary decision. The order held that the PUCT Staff’s proposed penalty calculation is unlawful and ruled partially in Luminant Energy’s favor, holding that the proper maximum penalty calculation should be based on the number of allegedly improper bid curves submitted to ERCOT during the relevant time period. The order also holds that a fact issue exists with respect to the number of bid curves submitted during the relevant period. Based upon this order and the PUCT Staff’s alleged number of bid curves, EFH Corp. believes that the maximum penalty would have been less than $16 million. The PUCT Staff appealed the administrative law judges’ ruling on this maximum penalty issue to the PUCT, and at the August 14, 2008 PUCT open meeting, the PUCT Commissioners determined that it was inappropriate to decide the issue of how to calculate the potential maximum penalty at this point in the case. Instead, the PUCT indicated that the maximum penalty issue should be determined as part of the final resolution of the entire proceeding, after a full hearing on the merits. On November 26, 2008, representatives of the parties to the NOV proceeding, wishing to avoid the expense and uncertainty of litigation, entered into a Settlement Agreement as a means of fully resolving all matters

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related to the NOV. Among other things, the Settlement Agreement provides for payment by Luminant of an administrative penalty of $15 million to the PUCT and acknowledgment from the PUCT Staff that Luminant’s Voluntary Mitigation Plan (“VMP”), which was filed with the PUCT in July 2007, continues to represent an appropriate safe harbor for Luminant from future enforcement actions for activities covered by the VMP. In addition, the PUCT Staff agreed that neither the payment of the penalty amount by Luminant nor anything in the Settlement Agreement should be construed as an admission of liability by Luminant. Luminant expressly denied such liability in the Settlement Agreement. The Settlement Agreement was approved by the PUCT in December 2008.

In June 2008, the EPA issued a request for information to Luminant Energy under EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. EFH Corp. is cooperating with the EPA and is responding in good faith to the EPA’s request. EFH Corp. is unable to predict the outcome of this matter.

Other Proceedings

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

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REGULATION AND RATES

Regulatory Investigations and Reviews

See Note 8 to the September 30, 2008 Financial Statements.

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. ERCOT has delayed the start of the nodal market beyond the January 1, 2009 implementation date. A revised cost-benefit analysis has been produced, and ERCOT has proposed a new date for the implementation of a nodal market of December 2010, but its proposed schedule does not yet have ERCOT board of directors or PUCT approval. EFH Corp. is currently unable to predict when a new nodal market implementation schedule will be approved by the PUCT.

In August 2006, the PUCT adopted an interim order approving ERCOT’s application for a surcharge imposed on all Qualified Scheduling Entities in the ERCOT market (including subsidiaries of TCEH) for the purpose of financing 38% of ERCOT’s expected nodal implementation costs. The surcharge took effect in October 2006. Additionally, at its January 15, 2008 meeting, the ERCOT Board of Directors agreed to request an increase in the surcharge to be effective in June 2008. ERCOT filed this request at the PUCT in March 2008 and it was approved by the PUCT in May 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 was no longer required to offer the price-to-beat rate to any of its customer classes.

Environmental Regulations

See discussion in Note 3 to the September 30, 2008 Financial Statements regarding the invalidation of the EPA’s Clean Air Interstate Rule and the related impairment of intangible assets representing NO_X and SO₂ emission allowances.

Oncor Matters with the PUCT

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

Rate Case—In June 2008, Oncor filed for a rate review with the PUCT (Docket No. 35717) and 204 cities, as required by the order approving the stipulation discussed above. If approved as requested, this review would result in an aggregate annual rate increase of approximately $253 million (such amount having been updated from $275 million as reflected in Oncor’s initial filing), the majority of which relates to increased depreciation expense due to capital investments and recovery of costs that have been recorded as regulatory assets. A procedural schedule was established in July 2008, with a hearing on the merits scheduled to commence on January 13, 2009. Resolution of Oncor’s proposed rate increase is expected to occur in 2009.

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 end of 2008.

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

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

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

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

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

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

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

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

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

As of September 30, 2008, Oncor had installed approximately 600,000 automated meters in its service territory at a capital cost of approximately $125 million. These meters are not part of the surcharge request, and Oncor is seeking recovery of the costs of these meters in its general rate case discussed above.

Oncor Energy Efficiency Cost Recovery Filing—In June 2008, Oncor filed with the PUCT a Request for Approval of Energy Efficiency Cost Recovery Factor (Docket No. 35634). Oncor requested a nonbypassable charge that will be billed to REPs serving customer classes that receive services under Oncor’s energy efficiency program. The recovery factor is $0.22 per month for each residential customer and will vary for non-residential customers. The charge will allow Oncor, in a timely manner, to recover reasonable and necessary costs incurred in administering its energy efficiency program. The charge, which was approved by the PUCT in October 2008, will go into effect on December 29, 2008, coinciding with the start of Oncor’s January 2009 billing month cycle.

Transmission Rates—In order to recover increases in its transmission costs, including fees paid to other transmission service providers, Oncor is allowed to request an update twice a year to the transmission cost recovery factor (TCRF) component of its retail delivery rate charged to REPs. In January 2008, an application was filed to increase the TCRF, which was administratively approved in February 2008 and became effective March 1, 2008. This increase is expected to increase annualized revenues by $12 million. In July 2008, an application was filed to increase the TCRF, which was approved on August 28, 2008 and became effective September 1, 2008. This increase is expected to increase annualized revenues by $26 million.

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In February 2008, Oncor filed an application for an interim update of its wholesale transmission rate. The PUCT approved Oncor’s application at its April 25, 2008 open meeting and the new rate went into effect immediately. Annualized revenues are expected to increase by approximately $39 million. Approximately $25 million of this increase is recoverable through transmission rates charged to wholesale customers, and the remaining $14 million is recoverable from REPs through the TCRF component of Oncor’s delivery rates charged to REPs and is included in the filing discussed immediately above.

Competitive Renewable Energy Zones (CREZ)—In the first quarter of 2007, the PUCT initiated a docket to identify the transmission facilities necessary to interconnect future renewable energy generating facilities. As part of the docket, the PUCT considered which zones would contain the best renewable energy sources. In July 2007, the PUCT voted to designate zones with generation potential of over 20,000 MW.

In the fourth quarter of 2007, the PUCT issued its Proposal for Publication for a new rule regarding the Selection of Transmission Service Providers (TSP) 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. The TSP selection rule was approved by the PUCT in May 2008, and the order adopting the new rule was issued in June 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 initiates 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. Oncor is participating in the settlement conference.

In July 2008, the PUCT approved the construction of transmission facilities with an estimated cost of $4.9 billion to accommodate over 18,000 MW of wind capacity. The PUCT will select the transmission service providers that will construct the facilities.

In September 2008, Oncor and several other ERCOT utilities filed a joint CREZ Transmission Plan, which includes the joint parties’ plans to construct and operate all of the CREZ transmission facilities. As part of this filing, Oncor proposes to build at least 1,000 miles of transmission lines and facilities in and around Oncor’s service territory, which based on ERCOT’s estimates will require an investment of more than $2 billion. Several other parties, including ERCOT and non-ERCOT entities, also filed CREZ Transmission Plans. Hearings on the CREZ Transmission Plan proposals were held in December 2008, and the PUCT is expected to issue a final order in the first quarter of 2009. Oncor cannot predict the amount of transmission facilities in CREZ that it will be awarded and that it will construct.

Summary

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

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MANAGEMENT

Directors

The names of EFH Corp.’s directors and information about them, as furnished by the directors themselves, are set forth below:

Name	Age	Served As Director Since	Business Experience
Arcilia C. Acosta (4)	43	2008	Arcilia C. Acosta has been President and CEO of CARCON Industries & Construction, based in Dallas, Texas, and specializing in commercial, institutional and transportation construction and president of Southwestern Testing Laboratories, a geotechnical engineering, construction materials testing and environmental consulting firm based in Dallas for the last seven years. Ms. Acosta currently serves as Chair of the Texas Association of Mexican American Chambers of Commerce.
David Bonderman	66	2007	David Bonderman is a founding partner of 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)	62	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 U.S. 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.
Thomas D. Ferguson	54	2008	Thomas D. Ferguson is a Managing Director of Goldman, Sachs & Co., having joined the firm in 2003. Mr. Ferguson is responsible for the asset management efforts for the infrastructure investment activity within the Merchant Bank. He currently serves on the boards of Associated British Ports, Carrix, National Golf Properties and Red de Carreteras Occidente.
Frederick M. Goltz (2)(3)	37	2007	Frederick M. Goltz has been with 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.

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Name	Age	Served As Director Since	Business Experience
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	33	2007	Scott Lebovitz is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He joined Goldman, Sachs & Co. in 1997. Mr. Lebovitz serves on the boards of both public and private companies including CVR Energy, Inc., Village Voice Media, LLC, EFC Holdings, TCEH, and Luminant.
Jeffrey Liaw (1)	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 its 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)	38	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.

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Name	Age	Served As Director Since	Business Experience
Lyndon L. Olson, Jr. (3)	61	2007	Lyndon L. Olson, Jr. was a Senior Advisor with Citigroup Inc. from 2002 to 2008, after serving as United States Ambassador to Sweden from 1998 to 2001. He previously was affiliated with Citigroup from 1990 to 1998, as President and Chief Executive Officer of Travelers Insurance Holdings and the Associated Madison Companies, predecessor companies. Before joining Citigroup, he had been President of the National Group Corporation and Chief Executive Officer of its National Group Insurance Company. Ambassador Olson also is a former Chairman and a Member of the Texas 173 State Board of Insurance, former President of the National Association of Insurance Commissioners, and a former member of the Texas House of Representatives.
Kenneth Pontarelli (2)(4)	38	2007	Kenneth Pontarelli 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.
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 sector. Mr. Reilly previously served as the seventh Administrator of the U.S. Environmental Protection Agency. Mr. Reilly is a director of the following public companies: E.I DuPont de Nemours and Company, Eden Springs, Ltd. of Israel, ConocoPhillips and Royal Caribbean International. Before serving as EPA Administrator, he was President of World Wildlife Fund and President of The Conservation Foundation. He previously served as Executive Director of the Rockefeller Task Force on Land Use and Urban Growth, a senior staff member of the President’s Council on Environmental Quality, and Associate Director of the Urban Policy Center and the National Urban Coalition. Mr. Reilly is Co-Chairman of the National Commission on Energy Policy.
Jonathan D. Smidt (1)	36	2007	Jonathan D. Smidt has 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.

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Name	Age	Served As Director Since	Business Experience
John F. Young (2)(3)	52	2008	John F. Young was elected President and Chief Executive Officer of EFH Corp. in January 2008. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon 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.
Kneeland Youngblood (1)	53	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

Audit Committee Financial Expert

The Board of Directors has determined that Donald L. Evans is an “Audit Committee Financial Expert” as defined by regulations of the SEC.

Though not formally considered by the Board of Directors because EFH Corp.’s common stock is not currently registered with the SEC or traded on any national securities exchange, based upon the listing standards of the NYSE, the national securities exchange upon which EFH Corp.’s common stock was traded prior to the Merger, only Ms. Acosta and Mr. Youngblood would be considered independent. Because of their relationships with the Sponsor Group or with EFH Corp. directly, none of the other directors would be considered independent. See “Certain Relationships and Related Party Transactions” and “Director Compensation.” Accordingly, we believe that Mr. Youngblood is the only member of the Audit Committee who would meet the independence requirements of Rule 10A-1 of the Exchange Act and the NYSE’s audit committee independence requirements. We believe that Ms. Acosta is the only member of the Organization and Compensation Committee who would meet the NYSE’s independence requirements. We believe that none of the members of our Governance and Public Affairs Committee would meet the NYSE’s independence requirements.

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Compensation Committee, Compensation Committee Interlocks and Insider Participation

During 2007, prior to the completion of the Merger, the Organization and Compensation Committee was composed of five non-employee, independent directors, each of whom satisfied the requirements for independence under applicable law and regulations. None of those persons had at any time been an officer or employee of EFH Corp. or any of its subsidiaries. The current Organization and Compensation Committee of the Board of Directors is comprised of three non-employee directors: Donald L. Evans, Marc S. Lipschultz and Kenneth Pontarelli. In addition, there were no relationships among our executive officers, members of the Organization and Compensation Committee or entities whose executives served on the Organization and Compensation Committee that required disclosure under applicable SEC rules and regulations.

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Executive Officers

The names and information regarding our executive officers are set forth below:

Name of Officer	Age	Positions and Offices Presently Held	Date First Elected to Present Offices	Business Experience (Preceding Five Years)
John F. Young	52	President and Chief Executive Officer of EFH Corp.	January 2008	John F. Young was elected President and Chief Executive Officer of EFH Corp. in January 2008. Before joining EFH Corp., Mr. Young served in a number of leadership roles at Exelon Corp. 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	40	President and Chief Executive of TXU Energy	August 2005	James A. Burke was elected President and Chief Executive of TXU Energy in August 2005. Previously, Mr. Burke was Senior Vice President Consumer Markets of TXU Energy. Prior to joining EFH Corp. in 2004, Mr. Burke was President and Chief Operating Officer of Gexa Energy.
David A. Campbell	40	President and Chief Executive of Luminant	June 2008	David A. Campbell was elected President and Chief Executive of Luminant in June 2008. Previously, Mr. Campbell held several other offices, including Executive Vice President and Chief Financial Officer of EFH Corp. Prior to joining EFH Corp. in 2004, Mr. Campbell was a Principal of McKinsey & Company, Inc.

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Name of Officer	Age	Positions and Offices Presently Held	Date First Elected to Present Offices	Business Experience (Preceding Five Years)
M. Rizwan Chand	45	Executive Vice President of EFH Corp.	May 2008	M. Rizwan Chand was elected Executive Vice President of EFH Corp. in May 2008, having served as Senior Vice President of EFH Corp. since 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	55	Executive Vice President and Chief Executive of Luminant Construction	September 2006	Charles R. Enze was elected Executive Vice President and Chief Executive of Luminant Construction in September 2006. Prior to joining EFH Corp. in 2006, Mr. Enze was Vice President of Engineering and Projects for Shell International Exploration & Production.
M. S. Greene	62	Vice Chairman of EFH Corp.	June 2008	M. S. Greene was elected Vice Chairman of EFH Corp. in June 2008. Previously Mr. Greene held several other offices including President and Chief Executive of Luminant and TCEH, Chairman of the Board, President and Chief Executive of TXU Power, Executive Vice President of TCEH, and Vice Chairman, Chief Executive and President of Oncor.
Paul M. Keglevic	54	Executive Vice President and Chief Financial Officer of EFH Corp.	July 2008	Paul M. Keglevic was elected Executive Vice President and Chief Financial Officer of EFH Corp. in July 2008. Before joining EFH Corp., Mr. Keglevic was an audit partner at PriceWaterhouseCoopers (“PwC”). Mr. Keglevic was PriceWaterhouseCoopers Utility Sector Leader from 2002 to 2008 and Clients and Sector Leader for the PwC Assurance Practice from 2007 to 2008.

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Name of Officer	Age	Positions and Offices Presently Held	Date First Elected to Present Offices	Business Experience (Preceding Five Years)
Michael T. McCall	51	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.
Mark A. McFarland	38	Executive Vice President and Chief Commercial Officer of Luminant and Executive Vice President of EFH Corp	July 2008	Mark A. (“Mac”) McFarland was elected Executive Vice President and Chief Commercial Officer of Luminant and Executive Vice President of EFH Corp. in July 2008. Prior to joining EFH Corp., Mr. McFarland was Senior Vice President of Corporate Development at Exelon Corporation.
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 L.L.P. and served on the firm’s management committee. Mr. Walters was co-managing partner of the Dallas office of Vinson & Elkins L.L.P. from 1998 through 2005.

There is no family relationship between any of the above-named executive officers.

Code of Conduct

EFH Corp. maintains certain corporate governance documents on EFH Corp’s website at www.energyfutureholdings.com. EFH Corp.’s Code of Conduct can be accessed by selecting “Investor Relations” on the EFH Corp. website. EFH Corp.’s Code of Conduct applies to all of its employees, officers (including the Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer) and directors. Any amendments to the Code of Conduct will be posted on EFH Corp.’s website. Printed copies of the corporate governance documents that are posted on EFH Corp.’s website are also available to any investor upon request to the Secretary of EFH Corp. at 1601 Bryan Street, Dallas, Texas 75201-3411.

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EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Overview

On October 10, 2007, Merger Sub merged with and into EFH Corp. As a result of the Merger, the Sponsor Group and the Investors indirectly own over 99% of our issued and outstanding common stock, no par value, through their investment in 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. After to the completion of the Merger, our Board of Directors (“Board”) 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 four non-employee directors: Donald L. Evans, Marc S. Lipschultz, Arcilia Acosta and Kenneth Pontarelli. 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 resulting 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 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 (the “Named Executive Officers”), the O&C Committee seeks the input of our CEO. At the end of each year, our CEO assesses the performance of each of these executive officers against targeted business unit and individual goals and objectives for that year and provides recommendations to the O&C Committee. The O&C Committee and the CEO then review the CEO’s assessments of 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 expect to also assess our compensation program against other privately-held companies and use compensation practices that are

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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.

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 EFH Corp. by:

• aligning performance measures with our business objectives to drive the financial and operational performance of EFH Corp. and its business units;

• rewarding business unit and individual performance by providing compensation levels consistent with the level of contribution and degree of accountability;

• attracting and retaining the best performers;

• 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 EFH Corp. and Affiliates (the “2007 Stock Incentive Plan”);

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• 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).

In addition, our Named Executive Officers are expected to make a minimum level of investment in our common stock. We believe this upfront investment further aligns the interests of our Named Executive Officers and stockholders and demonstrates their long-term commitment to EFH Corp. We refer to this 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 (such as 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.

The following is a discussion of the principal compensation components provided to our executive officers. More detail about each of the compensation elements that follow can be found in the compensation tables and the narrative and footnotes to the tables.

Base Salary

Base salary should reward executive officers for the scope and complexity of their position and the level of responsibility required. We believe that a competitive level of base salary is required to attract qualified talent.

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 EFH Corp. 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 remain at EFH Corp. 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. Both promotions came with substantially increased responsibilities;

• Mr. Burke’s salary had been frozen since he joined TXU Energy 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, 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 EFH Corp.’s Named Executive Officers

Name	Title (as of December 31, 2007)	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 did not change from October 2004 through December 2007.

(2) In order to incent Mr. Poole to remain with us through a transitional period following the Merger, in January 2008, we increased Mr. Poole’s base salary to the rate of $66,666 per month. Mr. Poole left EFH Corp. on March 31, 2008 and 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.

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

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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.

(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 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. 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 prospectus and defined in the glossary to this prospectus. 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, 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 EFH Corp. 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 EFH Corp. during a challenging year.

(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 EFH Corp. during a challenging year.

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(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 EFH Corp. in connection with the closing of the Merger. The award was paid on a target level performance.

(9) 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 award reflects a blend of the performance of those businesses, as well as his own strong contributions both before and after the Merger.

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

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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, were deposited into a rabbi trust, and our Named Executive Officers actually received their payouts (together with accrued interest) in January 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.

Equity Awards after the Merger

In December 2007, our Board approved and adopted the 2007 Stock Incentive Plan. The purpose of the 2007 Stock Incentive Plan is to promote our long term financial interests and growth by attracting and retaining management and other personnel with the training, experience and ability to enable them to make a substantial contribution to the success of our business; 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 EFH Corp. In June 2008, Messrs. Campbell, Greene, McCall and Burke were granted 4,000,000, 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, Messrs. Greene, McCall and Burke entered into Deferred Share Agreements with EFH Corp. in October 2007, 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. Also in connection with the Management Investment Opportunity, Mr. Campbell entered into a Deferred Share Agreement with EFH Corp. in May 2008, pursuant to which he agreed to forego certain payments he was entitled to receive in return for a certain number of deferred shares of our common stock. Pursuant to the terms of 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 Mr. Campbell agreed to reinvest a substantial portion of the amount that he was entitled to receive, and became entitled to receive 600,000, 600,000 and 450,000 deferred shares and 500,000 deferred shares, respectively, of our common stock, with each share being valued at $5.00 based upon the fully diluted equity of EFH Corp. The shares will be distributed to each of the executive officers on the earlier of the termination of such executive officer’s employment by EFH Corp. or a change in the effective control of EFH Corp.

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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 EFH Corp. achieving certain performance-based targets from 2008 through 2012 (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 would expect to maintain strong multi-year EBITDA performance if we do a good job serving all of our stakeholders while effectively managing our businesses.

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 was $5.00 for the options that were granted to Messrs. Campbell, Greene, McCall and Burke in June 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 EFH Corp.; 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

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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 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 Facilities to the extent considered appropriate for management compensation purposes.

Our EBITDA targets are also expected to be adjusted for acquisitions, divestitures or major capital investment initiatives to the extent that they were not contemplated in the 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.

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 EFH Corp. 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 does 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

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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 for a more detailed description of the Salary Deferral Program.

Retirement Plan: We maintain a retirement plan, which is qualified under applicable provisions of the Code and is a benefit for certain employees that were employed by us prior to 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 our 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 and Burke are covered under the cash balance component. While employed by EFH Corp., Mr. Wilder and Mr. Poole were 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.

Supplemental Retirement Plan: Our Supplemental Retirement Plan provides for the payment of retirement benefits that:

• would otherwise be capped by the Code’s statutory limits for qualified retirement plans;

• include Executive Annual Incentive Plan awards in the definition of earnings (for participants covered by the traditional 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 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.

Retiree Health Care:

Employees hired prior to January 1, 2002 are generally entitled to receive an employer paid subsidy for retiree health care coverage upon their retirement from EFH Corp. As such, Messers. Greene and McCall will be entitled to receive a subsidy from EFH Corp. for retiree health care coverage upon their retirement from EFH Corp. Following his retirement, Mr. Baker began to receive this subsidy. Because Messrs. Campbell, Poole and Burke were hired after January 1, 2002, they are not eligible for the employer subsidy.

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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.

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 and Mr. Poole, who are 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 EFH Corp. and this benefit is designed to help ensure their health and long-term ability to serve our shareholders.

Country Club/Luncheon Club Membership: We reimburse our executive officers for certain country club or luncheon club dues and expenses. We provide this perquisite to allow our executive officers to interact with, and cultivate relationships with, other business professionals and key community leaders and officials.

Expenditures for the perquisites outlined above are disclosed by individual in footnotes to the Summary Compensation Table.

Individual Compensation

Compensation of New CEO and New CFO

John F. Young

In January 2008, Mr. John F. Young became our Chief Executive Officer and President. He also serves as a member of our Board. In connection with his employment, we executed a five-year employment agreement with Mr. Young. After the initial five-year term, the employment agreement provides for automatic one year renewal periods until EFH Corp. 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 purchased $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 EFH Corp. Each restricted stock unit entitles Mr. Young to receive one share of our common stock. The restricted stock units were fully vested on the grant date, 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.

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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.

Mr. Young’s employment agreement includes customary non-compete and non-solicitation provisions that generally restrict Mr. Young’s ability to compete with us or solicit our customers or employees for his own personal benefit during the term of the employment agreement and 24 months after the employment agreement expires or is terminated.

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”.

Paul M. Keglevic

In July 2008, Mr. Paul M. Keglevic became our Executive Vice President and Chief Financial Officer. In connection with his employment, we executed a three-year employment agreement with Mr. Keglevic. As compensation for his services, Mr. Keglevic will be paid an annual base salary equal to $600,000 with the ability to earn an annual cash bonus equal to 75% of his base salary if he achieves certain annual performance targets established by the Board. Such annual cash bonus may be increased to an amount equal to 150% of his base salary based on achievement of certain superior annual performance targets established by the Board. The employment agreement also provides that we pay Mr. Keglevic a signing bonus equal to $550,000 as follows: (i) $250,000 payable on or before his second semi-monthly pay period of employment; (ii) $150,000 payable on the first anniversary of his employment and (iii) $50,000 payable on each of the second, third, and fourth anniversaries of his employment. Mr. Keglevic also received 2.5 million Stock Option Awards. Mr. Keglevic also received 225,000 deferred shares of our common stock. If Mr. Keglevic is employed by us on the third and fifth anniversaries of his employment, 112,500 of such deferred shares shall vest on each such date. If Mr. Keglevic’s employment with us terminates for any reason prior to July 1, 2013 (other than for “cause” or without “good reason”), he will have the right to (i) sell to us all (but not less than all) of the shares of our common stock that have vested pursuant to the deferred share arrangement (if any) for $3,200,000 or (ii) if no shares of our common stock shall have vested, a payment of $3,200,000. As part of his employment arrangement, Mr. Keglevic may purchase from us up to an aggregate number of shares of our common stock having a fair market value of $1,000,000. The employment agreement also entitles Mr. Keglevic to receive other forms of customary compensation such as certain health and welfare benefits, certain perquisites and reimbursement of certain business expenses.

Mr. Keglevic’s employment agreement includes a “change in control” provision. In the event that Mr. Keglevic’s employment is terminated by us without cause or if he resigns for good reason within 24 months after a “change in control”, Mr. Keglevic would be entitled to receive, among other things, a lump sum payment equal to two times the sum of his annualized base salary and his target annual cash bonus.

Mr. Keglevic’s employment agreement includes customary non-compete and non-solicitation provisions that generally restrict Mr. Keglevic’s ability to compete with us or solicit our customers or employees for his own personal benefit during the term of the employment agreement and 18 months after the employment agreement expires or is terminated.

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In addition to the employment agreement described above, Mr. Keglevic has entered into other agreements that govern his equity awards. For a more complete description of the agreements applicable to Mr. Keglevic’s investment in our common stock, please refer to the section entitled “Related Person Transactions”.

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.

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 upon the closing of the Merger, he received a prorated target award of $2,083,333.

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, at the closing of the Merger, 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 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 in January 2008 from certain rabbi trusts that were established at the closing of the Merger.

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. In 2008, Mr. Greene became the Vice Chairman of EFH Corp., and he ceased his role as CEO for Luminant.

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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 EFH Corp., 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 EFH Corp. in respect of outstanding equity awards issued prior to the Merger and became entitled to 600,000 deferred shares of our common stock. The shares will be distributed on the earlier of termination of employment with EFH Corp. or a change in the effective control of EFH Corp.

In June 2008, Mr. Greene was granted 2,000,000 Stock Option Awards as explained in the Long-Term Equity Incentives section under the heading “Equity Awards After the Merger.” 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, his retention was important and, thus, we agreed to a two year vesting period for his Time-Vesting Options.

We entered into a new two-year employment agreement with Mr. Greene in May 2008. The agreement provides 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 in May 2004, which was amended in September 2007 and October 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: In October 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 EFH Corp.’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 June 2008, Mr. Campbell was granted 4,000,000 Stock Option Awards as explained in the Long-Term Equity Incentives section under the heading “Equity Awards After the Merger.”

In September 2007 and October 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 EFH Corp. 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

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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).

We entered into a new three-year employment agreement with Mr. Campbell in May 2008, which term is automatically extended for successive one-year periods unless terminated by EFH Corp. or Mr. Campbell. The agreement provides that, during the term, Mr. Campbell will be entitled to the terms outlined below:

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 4,000,000 shares of our common stock of at a price per share of $5.00.

Other: As an inducement for entering into the agreement, Mr. Campbell is entitled to a one-time payment of $5,092,250, payable on the earlier of (x) a termination of employment for any reason or (y) January 15, 2009.

David P. Poole

We entered into an employment agreement with Mr. Poole in May 2004, which was amended in September 2007, October 2007 and January 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 2008 amendment to his employment agreement, Mr. Poole’s base salary was increased to the rate of $66,666 per month.

Annual Incentive: In October 2007, we entered into an Additional Payment Agreement with Mr. Poole, pursuant to which we 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 EFH Corp.’s results, as previously discussed, as well as Mr. Poole’s individual performance, he earned a bonus of $220,487.

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.

In January 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 EFH Corp. and (ii) $4,155,000, representing the amount agreed to be paid with regard to his ungranted 2008 and 2009 long term performance units (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 EFH Corp. in March 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 his increased responsibilities at Luminant.

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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 EFH Corp., Mr. McCall agreed to forego the right to receive certain payments from EFH Corp. in respect of outstanding equity awards issued prior to the Merger and became entitled to 600,000 deferred shares of our common stock. The shares will be distributed on the earlier of termination of employment with EFH Corp. or a change in the effective control of EFH Corp. In June 2008, Mr. McCall was granted 2,500,000 Stock Option Awards as explained in the Long-Term Equity Incentives section under the heading “Equity Awards After the Merger.”

We entered into a new employment agreement with Mr. McCall in May 2008, which employment agreement was amended and restated in June 2008. The amended and restated agreement provides for Mr. McCall’s service during a three-year term, which term is automatically extended for successive one-year periods unless terminated by EFH Corp. or Mr. McCall. The amended and restated agreement provide that, during the 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.

Other: As consideration for remaining actively employed with EFH Corp., Mr. McCall is entitled to a one-time payment of $1,750,000, payable on the earlier of (x) a qualifying termination of employment or (y) June 30, 2009. Mr. McCall will otherwise forfeit such amount if he is terminated by EFH Corp. with cause or resigns without good reason on or before June 30, 2009.

James A. Burke

Mr. Burke’s previous agreement with TXU Energy 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 of TXU Energy in 2004. He was promoted to CEO of TXU Energy in 2005, but his salary remained frozen. Following the Merger, Mr. Burke’s salary was increased to $600,000, in recognition of a more appropriate salary for his responsibilities.

Annual Incentive: Mr. Burke’s target annual incentive prior to the Merger was 60% of base salary; however, for the period beginning October 10, 2007 and ending December 31, 2007, Mr. Burke’s target annual incentive was increased to 75% of base salary. In October 2007, we entered into an Additional Payment Agreement with Mr. Burke, pursuant to which we 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 EFH Corp., 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 EFH Corp. in respect of outstanding equity awards issued prior to the Merger and became entitled to 450,000 deferred shares of our common stock. The shares will be distributed on the earlier of termination of employment with EFH Corp. or a change in the

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effective control of EFH Corp. In June 2008, Mr. Burke was granted 2,450,000 Stock Option Awards as explained in the Long-Term Equity Incentives section under the heading “Equity Awards After the Merger.”

We entered into a new employment agreement with Mr. Burke in May 2008. 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 us 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 entered into a consulting agreement with Mr. Baker in May 2008. The consulting agreement has a term of up to two years and will provide for an annual consulting fee of $250,000. In addition, Mr. Baker received 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 EFH Corp. during such period.

Contingent Payments

We have entered into an employment agreement with Messrs. Campbell, Greene, McCall and Burke. Each of the employment agreements provides that certain payments and benefits will be paid upon the expiration or termination of the agreement under various circumstances, including termination without cause, resignation for good reason and termination of employment within a fixed period of time following a change in control. 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 the employment agreements and our change in control policy and severance plan see “Potential Payments upon Termination or Change in Control.”

We believe these provisions are important in order to attract and retain the caliber of executive officers that our business requires and provide incentive for our executive officers to fully consider potential changes that are in our and our shareholders’ best interest, even if such changes would result in the executive officers’ termination.

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

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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 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 Code.

The 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, were excess parachute payments and were not deductible by EFH Corp., nor were any of the underlying excess parachute payments that gave rise to the excise tax.

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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	2007	536,792	596,284	384,065	189,411	347,747	2,054,299
President and CEO of Luminant	2006	507,000	1,145,979	220,000	1,222,893	229,765	3,325,637
David A. Campbell	2007	382,000	1,339,728	300,481	14,667	2,342,814	4,379,690
Executive Vice President and Chief Financial Officer of EFH Corp.	2006	382,000	1,311,787	230,000	30,639	53,682	2,008,108
David P. Poole	2007	307,000	1,099,176	220,487	13,388	2,627,981	4,268,032
Executive Vice President and Former General Counsel of EFH Corp.	2006	307,000	841,275	120,000	22,696	43,082	1,334,053
Michael T. McCall	2007	345,958	521,450	145,800	77,035	116,712	1,206,955
Chief Operating Officer of Luminant	2006	232,000	541,274	140,000	153,820	93,336	1,160,430
James A. Burke	2007	342,712	454,478	274,050	9,864	978,189	2,059,293
President and CEO of TXU Energy	2006	275,004	512,932	100,000	15,962	52,233	956,131
C. John Wilder	2007	989,583	9,026,216	0	103,076	27,843,146	37,962,021
Former CEO of EFH Corp.	2006	1,250,000	6,390,038	1,625,000	185,454	564,056	10,014,548
T. L. Baker	2007	536,242	350,298	337,488	23,800	438,614	1,686,442
Chairman Emeritus of EFH Corp.	2006	632,000	459,986	130,000	580,050	302,169	2,104,205

(1) As more fully discussed under the section entitled “Base Salary”, 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.

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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. 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.

(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”. 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 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 and Burke are covered under the cash balance component. While employed by EFH Corp., Mr. Wilder and Mr. Poole were also covered under the cash balance program. For a more detailed description of EFH Corp.’s retirement plans, please refer to the narrative that follows the Pension Benefits table. There are no above market earnings for nonqualified deferred compensation.

(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, in January 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 Code

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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.

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 in October 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 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

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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.

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” 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. sold its aircraft and no longer owns or operates 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.

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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”.

(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.

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Outstanding Equity Awards at Fiscal Year-End—2007

As a result of the Merger, there were no unvested stock awards under the 2005 Omnibus Incentive Plan held by the Named Executive Officers as of December 31, 2007.

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

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

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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 because they were paid in October 2007 as a result of the Merger.

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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.

(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 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

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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 Code.

The Supplemental Retirement Plan provides for the payment of retirement benefits, which would otherwise be limited by the Code or the definition of earnings under the Retirement Plan. The Supplemental Retirement Plan also provides for the payment of retirement compensation that is not otherwise payable under the Retirement Plan that EFH Corp. or its participating subsidiaries are obligated to pay under contractual arrangements. Under the Supplemental Retirement Plan, retirement benefits are calculated in accordance with the same formula used under the Retirement Plan, except that, with respect to calculating the portion of the Supplemental Retirement Plan benefit attributable to service under the traditional 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 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.

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

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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 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.

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. 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.

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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 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.

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

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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: As of December 31, 2007, each of Messrs. Campbell, Poole and Burke had 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 govern until Mr. Poole left EFH Corp. in March 2008 and Messrs. Campbell and Burke entered into new employment agreements in June 2008. 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. Messrs. Campbell, Greene, McCall and Burke executed employment agreements with EFH Corp. in June 2008 that included change in control and severance provisions. These provisions are consistent with the change in control and severance provisions contained in Mr. Burke’s employment agreement as of December 31, 2007.

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 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 EFH Corp. 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 EFH Corp.’s health care benefit plans for two years;

3. outplacement assistance at EFH Corp.’s expense for 18 months and

4. any vested accrued benefits to which the executive is entitled under EFH Corp.’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 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.

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.

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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.

1. Mr. Greene

Potential Payments to Mr. Greene Upon Termination (per company policy as of December 31, 2007)

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.

(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 as of December 31, 2007)

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.

At December 31, 2007, Mr. Campbell’s employment agreement, as amended, provided 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:

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;

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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 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.

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3. Mr. Poole

Potential Payments to Mr. Poole Upon Termination (per employment agreement as of December 31, 2007)

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.

(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.

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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:

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 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.

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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 had no right to any payment under EFH Corp.’s bonus plans for calendar year 2008 nor did 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.

Mr. Poole left EFH Corp. in March 2008 when Mr. Robert C. Walters was hired to serve as our General Counsel.

4. Mr. McCall

Potential Payments to Mr. McCall Upon Termination (per EFH Corp. policy as of December 31, 2007)

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.

(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 as of December 31, 2007)

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;

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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.

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 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, Greene, McCall 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 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 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 Code section 409A.

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DIRECTOR COMPENSATION

The table below sets forth information regarding the aggregate compensation paid to each member of our Board (including current and former members) during the fiscal year ended December 31, 2007. Directors who are officers, or former officers, of EFH Corp. did and 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 EFH Corp.’s decision to discontinue owning and operating aircraft, directors were permitted to use company aircraft for travel related to their services as directors.

Name	Fees Earned or Paid in Cash ($)	Stock Awards ($)	All Other Compensation ($)	Total ($)
Arcilia C. Acosta (1)(2)(3)	n/a	n/a	n/a	n/a
David Bonderman (3)	n/a	n/a	n/a	n/a
Donald L. Evans (2)(4)	1,500,000	0	0	1,500,000
Thomas D. Ferguson (1)(3)	n/a	n/a	n/a	n/a
Frederick M. Goltz (3)	n/a	n/a	n/a	n/a
James R. Huffines (2)(3)(5)	37,500	0	56,250	93,750
Scott Lebovitz (3)	n/a	n/a	n/a	n/a
Jeffrey Liaw (3)	n/a	n/a	n/a	n/a
Marc S. Lipschultz (3)	n/a	n/a	n/a	n/a
Michael MacDougall (3)	n/a	n/a	n/a	n/a
Lyndon L. Olson, Jr. (2)(3)(5)	37,500	0	56,250	93,750
Kenneth Pontarelli (3)	n/a	n/a	n/a	n/a
William K. Reilly (2)(3)	37,500	0	0	37,500
Jonathan D. Smidt (3)	n/a	n/a	n/a	n/a
William Young (3)(8)	n/a	n/a	n/a	n/a
Kneeland Youngblood (2)(3)	37,500	0	0	37,500
Leldon E. Echols (6)	207,500	100,000	0	307,500
Steven Feldman (7)	n/a	n/a	n/a	n/a
Kerney Laday (6)	98,000	100,000	0	198,000
Jack E. Little (6)	210,500	100,000	0	310,500
Gerardo I. Lopez (6)	88,500	100,000	0	188,500
J. E. Oesterreicher (6)	160,500	100,000	0	260,500
Michael W. Ranger (6)	205,000	100,000	0	305,000
Leonard H. Roberts (6)	154,500	100,000	0	254,500
Glenn F. Tilton (6)	184,500	100,000	0	284,500
E. Gail de Planque (6)	21,250	100,000	0	121,250

(1) Ms. Acosta and Mr. Ferguson were not members of the Board in 2007.

(2) In the second quarter of 2008, Messrs. Evans, Huffines, Olson, Reilly and Youngblood purchased shares of EFH Corp.’s common stock at a price of $5.00 per share, and Messrs. Huffines, Olson and Reilly were each granted 120,000 shares of EFH Corp.’s common stock at a price of $5.00 per share. In August 2008, Ms. Acosta purchased shares of EFH Corp.’s common stock at a price of $7.00 per share. In connection with these purchases and with their grants of equity, these directors entered into stockholder agreements and sale participation agreements with EFH Corp. The stockholder agreements create certain rights and restrictions on such equity, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances. Pursuant to the terms of the sale participation agreements, shares of EFH Corp.’s common stock held by these individuals 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.

(3) 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. Ms. Acosta and Messrs. Huffines, Olson, Reilly

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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.

(4) In May 2008, EFH Corp. entered into a consulting agreement with Mr. Evans, pursuant to which he received 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 also acknowledges 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 has a term running through October 10, 2009, subject to extension upon mutual agreement of up to three additional years.

(5) In December 2007, EFH Corp. entered into consulting agreements with Messrs. Huffines and Olson with terms of up to five years. As compensation for their consulting services, they receive annual fees of $225,000, which fees are in addition to their standard director compensation arrangements described above. The amounts earned pursuant to these consulting agreements in 2007 are reflected above in the “All Other Compensation” column.

(6) 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 TXU 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 TXU Corp. 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 TXU Corp. 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 TXU Corp. 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 TXU Corp. 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.

(7) Mr. Feldman served as a director of the Board from October 10, 2007 until October 16, 2007.

(8) Mr. Young is no longer a member of the Board.

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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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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Equity Compensation Plan Information

The following table presents information concerning stock-based compensation plans as of August 31, 2008. See Note 23 to the 2007 year-end Financial Statements for discussion of stock-based compensation plans.

	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans, excluding securities reflected in column (a)
Equity compensation plans approved by security holders	—	$	—	—
Equity compensation plans not approved by security holders	46,119,000	$	5.00	13,680,460
	46,119,000	$	5.00	13,680,460

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Beneficial Ownership of Common Stock of EFH 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 September 30, 2008.

Name	Number of Shares Beneficially Owned	Percent of Class
Texas Energy Future Holdings Limited Partnership (1)	1,657,600,000	98.99	%
Arcilia C. Acosta (2)	50,000	*
David Bonderman (3)	1,657,600,000	98.99	%
Donald L. Evans (4)	700,000	*
Frederick M. Goltz (5)	1,657,600,000	98.99	%
James R. Huffines	340,000	*
Scott Lebovitz (6)	1,657,600,000	98.99	%
Jeffrey Liaw (3)	1,657,600,000	98.99	%
Marc S. Lipschultz (5)	1,657,600,000	98.99	%
Michael MacDougall (3)	1,657,600,000	98.99	%
Lyndon L. Olson, Jr.	200,000	*
Kenneth Pontarelli (6)	1,657,600,000	98.99	%
William K. Reilly	180,000	*
Jonathan D. Smidt (5)	1,657,600,000	98.99	%
John F. Young (7)	1,950,000	*
William Young (6)(17)	1,657,600,000	98.99	%
Kneeland Youngblood	120,000	*
M. S. Greene (8)	1,100,000	*
David A. Campbell (9)	900,000	*
David P. Poole	—	—
Robert C. Walters (10)	200,000	*
Michael T. McCall (11)	850,000	*
James A. Burke (12)	695,000	*
C. John Wilder	—	—
T. L. Baker	60,000	*
Paul M. Keglevic (13)	250,000	*
Mark A. McFarland (14)	200,000	*
Charles R. Enze (15)	460,000	*
M. Rizwan Chand (16)	235,000	*
All directors and current executive officers as a group (25 persons)	1,666,030,000	99.49	%

 * Less than 1%.

(1) Texas Energy Future Holdings Limited Partnership (“Texas Holdings”) beneficially owns 1,657,600,000 shares of EFH. The sole general partner of Texas Holdings is Texas Energy Future Capital Holdings LLC (“Texas Capital”), which, pursuant to the Amended and Restated Limited Partnership Agreement of Texas Holdings, has the right to vote all of the EFH Corp. shares owned by Texas Holdings. The address of both Texas Holdings and Texas Capital is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.

(2) Shares held in a family limited partnership, ACA Family LP.

(3) Includes the 1,657,600,000 shares owned by Texas Holdings, over which TPG Partners V, L.P., TPG Partners IV, L.P., TPG FOF V-A, L.P. and TPG FOF V-B, L.P. (the “TPG Entities”) may be deemed, as a result of their ownership of 27.01% of Texas Capital’s outstanding units and certain provisions of Texas Capital’s Amended and Restated Limited Liability Company Agreement (“LLC Agreement”), to have shared voting or dispositive power. The ultimate general partners of the TPG Entities are TPG Advisors IV Inc. and TPG Advisors V Inc. David Bonderman and James Coulter are the sole shareholders and directors

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of TPG Advisors IV Inc. and TPG Advisors V Inc., and therefore, Messrs. Bonderman and Coulter, TPG Advisors IV Inc. and TPG Advisors V Inc. may each be deemed to beneficially own the shares held by the TPG Entities. Messrs. Bonderman, Liaw and MacDougall are managers of Texas Capital 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.

(4) Includes 300,000 shares issuable upon exercise of vested options.

(5) Includes the 1,657,600,000 shares owned by Texas Holdings, over which 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.

(6) 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 William 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.

(7) Includes 750,000 shares issuable upon exercise of vested options.

(8) Includes 600,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 500,000 shares issuable upon exercise of vested options.

(9) Includes 500,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. 400,000 shares issuable upon exercise of vested options.

(10) Includes 200,000 shares issuable upon exercise of vested options.

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(11) Includes 600,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 250,000 shares issuable upon exercise of vested options.

(12) Includes 450,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 245,000 shares issuable upon exercise of vested options.

(13) Includes 250,000 shares issuable upon exercise of vested options.

(14) Includes 200,000 shares issuable upon exercise of vested options.

(15) Includes 200,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 160,000 shares issuable upon exercise of vested options.

(16) Includes 175,000 shares issuable upon exercise of vested options.

(17) Mr. Young is no longer a member of the Board. Mr. Thomas D. Ferguson, a manager of Texas Capital and an executive with an affiliate of Goldman Sachs, has replaced Mr. Young as a member of the Board.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Policies and Procedures Relating to Related Party Transactions

The Board has adopted a policy regarding related person transactions. Under this policy, a related person transaction shall be consummated or shall continue only if:

1. the Audit Committee of the Board approves or ratifies such transaction in accordance with the policy and if the transaction is on terms comparable to those that could be obtained in arm’s length dealings with an unrelated third party;

2. the transaction is approved by the disinterested members of the Board; or

3. the transaction involves compensation approved by the Organization and Compensation Committee of the Board.

For purposes of this policy, the term “related person” includes EFH Corp.’s directors, executive officers, 5% shareholders and their immediate family members. “Immediate family members” means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law or any person (other than a tenant or employee) sharing the household of a director, executive officer or 5% shareholder.

A “related person transaction” is a transaction between EFH Corp. or its subsidiaries and a related person (including any transactions requiring disclosure under Item 404 of Regulation S-K under the Securities Act, if applicable), other than the types of transactions described below, which are deemed to be pre-approved by the Audit Committee of the Board:

1. any compensation paid to a director if the compensation is required to be reported under Item 402 of Regulation S-K of the Securities Act;

2. any transaction with another company at which a related person’s only relationship is as an employee (other than an executive officer), director or beneficial owner of less than 10% of that company’s ownership interests;

3. any charitable contribution, grant or endowment by EFH Corp. to a charitable organization, foundation or university at which a related person’s only relationship is as an employee (other than an executive officer) or director;

4. transactions where the related person’s interest arises solely from the ownership of EFH Corp.’s equity securities and all holders of that class of equity securities received the same benefit on a pro rata basis;

5. transactions involving a related party where the rates or charges involved are determined by competitive bids;

6. any transaction with a related party involving the rendering of services as a common or contract carrier, or public utility, as rates or charges fixed in conformity with law or governmental authority;

7. any transaction with a related party involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture, or similar service;

8. transactions available to all employees or customers generally (unless required to be disclosed under Item 404 of Regulation S-K of the Securities Act, if applicable); and

9. transactions involving less than $100,000 when aggregated with all similar transactions.

The Board has determined that it is appropriate for the Audit Committee of the Board to review and approve or ratify related person transactions. Accordingly, at least annually, management reviews related person transactions to be entered into by EFH Corp. or its subsidiaries, if any. After review, the Audit Committee of the

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Board approves/ratifies or disapproves such transactions. Management updates the Audit Committee of the Board as to any material changes to such related person transactions. In unusual circumstances, EFH Corp. or its subsidiaries may enter into related person transactions in advance of receiving approval, provided that such related person transactions are reviewed and ratified as soon as reasonably practicable by the Audit Committee of the Board. If the Audit Committee of the Board determines not to ratify such transactions, EFH Corp. shall make all reasonable efforts to cancel or otherwise terminate such transactions.

The related person transactions described below under the heading “Business Affiliations,” were ratified by the Audit Committee of the Board pursuant to the policy described above. All other related person transactions were approved prior to the Board’s adoption of this policy, but were approved by either the Board or its Executive Committee.

Related Person Transactions

Limited Partnership Agreement of Texas Energy Future Holdings Limited Partnership; Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC

The Sponsor Group and certain investors who agreed to co-invest with the Sponsor Group or through a vehicle jointly controlled by the Sponsor Group to provide equity financing for the merger (“Co-Investors”), entered into (i) a limited partnership agreement (the “LP Agreement”) in respect of EFH Corp.’s parent company, Texas Holdings and (ii) the LLC Agreement in respect of Texas Holdings’ sole general partner, Texas Capital. The LP Agreement provides that Texas Capital has the right to vote or execute consents with respect to any shares of EFH Corp.’s common stock owned by Texas Holdings. The LLC Agreement and LP Agreement contain agreements among the parties with respect to the election of EFH Corp.’s directors, restrictions on the issuance or transfer of interests in EFH Corp., including tag-along rights and drag-along rights, and other corporate governance provisions (including the right to approve various corporate actions).

The LLC Agreement provides that Texas Capital and its members will take all action required to ensure that the managers of Texas Capital are also members of EFH Corp.’s Board of Directors. Pursuant to the LLC Agreement each of (i) KKR 2006 Fund L.P. and affiliated investment funds, (ii) TPG Partners V, L.P. and affiliated investment funds and (iii) certain funds affiliated with Goldman Sachs, has the right to designate three managers of Texas Capital. These rights are subject to maintenance of certain investment levels in Texas Holdings.

Registration Rights Agreement

The Sponsor Group and the Co-Investors entered into a registration rights agreement with EFH Corp. upon completion of the Merger. Pursuant to this agreement, in certain circumstances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.’s common stock owned directly or indirectly by them under the Securities Act. In certain circumstances, the Sponsor Group and the Co-Investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.’s common stock under the Securities Act that it may undertake. In January 2008, John Young became a party to this agreement. In 2008, Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and Messrs. John Young, Greene, Campbell, Walters, McCall, Burke, Keglevic and McFarland, each of whom are executive officers of EFH Corp., became parties to this agreement.

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

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annual management fee of $35 million, which amount will increase 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of EFH Corp. or in connection with an initial public offering of EFH Corp. or if the parties thereto mutually agree to terminate the Management Agreement. Pursuant to the Management Agreement, affiliates of the Sponsor Group and Lehman Brothers Inc. were paid transaction fees of $300 million for certain services provided in connection with the Merger and related transactions. In addition, the Management Agreement provides that the Sponsor Group will be entitled to receive a fee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition, merger combination and change of control transactions, as well as a termination fee based on the net present value of future payment obligations under the Management Agreement in the event of an initial public offering or under certain other circumstances. Under terms of the Management Agreement, EFH Corp. paid $8 million to the Sponsor Group for the period from October 11, 2007 to December 31, 2007 and approximately $26 million for the period from January 1, 2008 to September 30, 2008.

Indemnification Agreement

Concurrently with entering into the Management Agreement, the Sponsor Group, Texas Holdings and EFH Corp. entered into an indemnification agreement (the “Indemnification Agreement”), pursuant to which EFH Corp. and Texas Holdings agree to indemnify the Sponsor Group and their affiliates against any claims relating to (i) certain securities and financing transactions relating to the Merger, (ii) the performance of transaction services pursuant to the Management Agreement, (iii) actions or failures to act by EFH Corp., Texas Holdings, Texas Capital or their subsidiaries or affiliates (collectively, the “Company Group”), (iv) service as an officer or director of, or at the request of, any member of the Company Group, and (v) any breach or alleged breach of fiduciary duty as a director or officer of any member of the Company Group.

Sale Participation Agreement

In January 2008, John F. Young entered into, and in the second and third quarters of 2008, Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and Messrs. Greene, Campbell, Walters, McCall, Burke, Keglevic and McFarland, each of whom are executive officers of EFH Corp., entered 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, among other things, shares of EFH Corp.’s common stock held by these individuals are subject to tag-along and drag-along rights in the event of a sale by the Sponsor Group of shares of EFH Corp.’s common stock held by the Sponsor Group.

Certain Charter Provisions

EFH Corp.’s restated certificate of formation contains provisions limiting directors’ obligations in respect of corporate opportunities.

Management Stockholders’ Agreement

Subject to a management stockholders’ agreement, certain members of management, including EFH Corp.’s executive officers, along with other members of management, elected to invest in EFH Corp. by contributing cash or common stock, or a combination of both, to EFH Corp. prior to or following the Merger and receiving common stock in EFH Corp. in exchange therefore. The aggregate amount of this investment as of August 31, 2008 is approximately $44 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 the second and third quarters of 2008, certain members of our Board entered into a stockholders’ agreement with EFH Corp. See Item 11. Executive Compensation “Director Compensation”.

Business Affiliations

Mr. Olson, a member of our board, has an ownership interest in two companies with which Oncor does business. These companies are Texas Meter and Device Company (“TMD”) and Metrum Technologies LLC (“Metrum”). Mr. Olson and his brother collectively directly own approximately 24% of TMD and indirectly own approximately 19% of Metrum. Both entities are majority owned by their chief executive officer. In 2007, Oncor paid TMD approximately $170,000 and paid Metrum approximately $2.4 million. TMD tests Oncor’s high voltage personal protective equipment. Metrum provides Oncor with cellular-based wireless communications equipment for its meters. Amounts paid to these companies by Oncor represent approximately 30% of Metrum’s annual revenue and Oncor is Metrum’s largest customer. The business relationships with both TMD and Metrum commenced several years prior to Mr. Olson joining EFH Corp.’s Board.

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THE EXCHANGE OFFERS

Purpose and Effect of the Exchange Offers

EFH Corp. and the guarantors of the outstanding notes have entered into a registration rights agreement with the initial purchasers of the outstanding notes in which we agreed, under certain circumstances, to file a registration statement relating to offers to exchange the outstanding notes for exchange notes and to use all commercially reasonable efforts to cause such registration statement to become effective under the Securities Act within 360 days after the date of original issuance of the outstanding notes. The exchange notes will have terms identical in all material respects to the outstanding notes, except that the exchange notes will not contain terms with respect to transfer restrictions, registration rights and additional interest for failure to observe certain obligations in the registration rights agreement. The outstanding notes were issued on October 31, 2007.

Under the circumstances set forth below, EFH Corp. and the guarantors will use all commercially reasonable efforts to cause the SEC to declare effective a shelf registration statement with respect to the resale of the outstanding notes within the time periods specified in the registration rights agreement and keep the statement effective for up to two years after the effective date of the shelf registration statement. These circumstances include:

• if any changes in law, SEC rules or regulations or applicable interpretations thereof by the SEC do not permit us to effect the exchange offers as contemplated by the registration rights agreement;

• if the exchange offers are not consummated within 60 business days after the registration statement of which this prospectus is a part is declared effective or 360 days after the date of issuance of the outstanding notes; or

• if any holder of outstanding notes notifies EFH Corp. within 20 business days of the completion of the exchange offers that: (A) you are prohibited by law or SEC policy from participating in the exchange offers, (B) you may not resell the exchange notes to the public without delivering a prospectus and this prospectus is not appropriate or available for such resales or (C) you are a broker-dealer and own outstanding notes acquired directly from EFH Corp. or an affiliate of EFH Corp.

Under the registration rights agreement, if EFH Corp. fails to complete the exchange offers (other than in the event we file a shelf registration statement) or the shelf registration statement, if required thereby, is not declared effective, in either case on or prior to 360 days after the issue date of the outstanding notes (the “target registration date”), the interest rate on each series of the outstanding notes will be increased by (x) 0.25% per annum for the first 90-day period immediately following the target registration date and (y) an additional 0.25% per annum thereafter, in each case, until the exchange offers are completed or the shelf registration statement, if required, is declared effective by the SEC or the outstanding notes cease to constitute transfer restricted notes. A copy of the registration rights agreement has been filed as an exhibit to the registration statement of which this prospectus is a part.

If you wish to exchange your outstanding notes for exchange notes in any of the exchange offers, you will be required to make the following written representations:

• you are not our affiliate within the meaning of Rule 405 of the Securities Act or if you are an “affiliate”, you will comply with the registration and prospectus delivery requirements of the Securities Act;

• you have no arrangement or understanding with any person to participate in a distribution (within the meaning of the Securities Act) of the exchange notes in violation of the provisions of the Securities Act;

• you are not engaged in, and do not intend to engage in, a distribution of the exchange notes;

• you are acquiring the exchange notes in the ordinary course of your business;

• if you are a broker-dealer, that you did not purchase the outstanding notes to be exchanged in the exchange offers from EFH Corp. or any of its affiliates; and

• you are not acting on behalf of any person who could not truthfully and completely make the above representations.

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Each broker-dealer that receives exchange notes for its own account in exchange for outstanding notes, where the broker-dealer acquired the outstanding notes as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. Please see “Plan of Distribution.”

Resale of Exchange Notes

Based on interpretations by the SEC set forth in no-action letters issued to third parties, we believe that you may resell or otherwise transfer exchange notes issued in the exchange offers without complying with the registration and prospectus delivery provisions of the Securities Act if:

• you are not our affiliate or an affiliate of any guarantor within the meaning of Rule 405 under the Securities Act;

• you do not have an arrangement or understanding with any person to participate in a distribution of the exchange notes;

• you are not engaged in, and do not intend to engage in, a distribution of the exchange notes; and

• you are acquiring the exchange notes in the ordinary course of your business.

If you are our affiliate or an affiliate of any guarantor, or are engaging in, or intend to engage in, or have any arrangement or understanding with any person to participate in, a distribution of the exchange notes, or are not acquiring the exchange notes in the ordinary course of your business:

• you cannot rely on the position of the SEC set forth in Morgan Stanley & Co. Incorporated (available June 5, 1991) and Exxon Capital Holdings Corporation (available May 13, 1988), as interpreted in the SEC’s letter to Shearman & Sterling, dated July 2, 1993, or similar no-action letters; and

• in the absence of an exception from the position stated immediately above, you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the exchange notes.

This prospectus may be used for an offer to resell, resale or other transfer of exchange notes only as specifically set forth in this prospectus. With regard to broker-dealers, only broker-dealers that acquired the outstanding notes as a result of market-making activities or other trading activities may participate in the exchange offers. Each broker-dealer that receives exchange notes for its own account in exchange for outstanding notes, where such outstanding notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of the exchange notes. Please read “Plan of Distribution” for more details regarding the transfer of exchange notes.

Terms of the Exchange Offers

On the terms and subject to the conditions set forth in this prospectus and in the accompanying letters of transmittal, EFH Corp. will accept for exchange in the exchange offers any outstanding notes that are validly tendered and not validly withdrawn prior to the expiration date. Outstanding notes may only be tendered in minimum denominations of $2,000 and integral multiples of $1,000 in excess of $2,000. EFH Corp. will issue exchange notes in principal amount identical to outstanding notes surrendered in the exchange offers.

The form and terms of the exchange notes will be identical in all material respects to the form and terms of the outstanding notes except the exchange notes will be registered under the Securities Act, will not bear legends restricting their transfer and will not provide for any additional interest upon our failure to fulfill our obligations under the registration rights agreement to complete the exchange offers, or file, and cause to be effective, a shelf registration statement, if required thereby, within the specified time period. The exchange notes will evidence the same debt as the outstanding notes. The exchange notes will be issued under and entitled to the benefits of the indenture that authorized the issuance of the outstanding notes. For a description of the indenture, see “Description of Notes.”

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The exchange offers are not conditioned upon any minimum aggregate principal amount of outstanding notes being tendered for exchange.

As of the date of this prospectus, $2,000 million aggregate principal amount of the 10.875% Senior Notes due 2017 are outstanding and $2,500 million aggregate principal amount of the 11.250%/12.000% Senior Toggle Notes due 2017 are outstanding. This prospectus and the letters of transmittal are being sent to all registered holders of outstanding notes. There will be no fixed record date for determining registered holders of outstanding notes entitled to participate in the exchange offers. EFH Corp. intends to conduct the exchange offers in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Exchange Act, and the rules and regulations of the SEC. Outstanding notes that are not tendered for exchange in the exchange offers will remain outstanding and continue to accrue interest and will be entitled to the rights and benefits such holders have under the indenture relating to such holders’ series of outstanding notes except we will not have any further obligation to you to provide for the registration of the outstanding notes under the registration rights agreement.

EFH Corp. will be deemed to have accepted for exchange properly tendered outstanding notes when it has given oral or written notice of the acceptance to the exchange agent. The exchange agent will act as agent for the tendering holders for the purposes of receiving the exchange notes from us and delivering exchange notes to holders. Subject to the terms of the registration rights agreement, EFH Corp. expressly reserves the right to amend or terminate any of the exchange offers and to reject for exchange any outstanding notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offers specified below under “—Conditions to the Exchange Offers.”

If you tender your outstanding notes in the exchange offers, you will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes with respect to the exchange of outstanding notes. We will pay all charges and expenses, other than certain applicable taxes described below in connection with the exchange offers. It is important that you read “—Fees and Expenses” below for more details regarding fees and expenses incurred in the exchange offers.

Expiration Date, Extensions and Amendments

As used in this prospectus, the term “expiration date” means 11:59 p.m., New York City time, on                 , 2009. However, if we, in our sole discretion, extend the period of time for which the exchange offers are open, the term “expiration date” will mean the latest time and date to which we shall have extended the expiration of the exchange offers.

To extend the period of time during which the exchange offers are open, we will notify the exchange agent of any extension by oral or written notice, followed by notification by press release or other public announcement to the registered holders of the outstanding notes no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date.

EFH Corp. reserves the right, in its sole discretion:

• to delay accepting for exchange any outstanding notes (only in the case that we amend or extend the exchange offers);

• to extend any of the exchange offers or to terminate any of the exchange offers if any of the conditions set forth below under “—Conditions to the Exchange Offers” have not been satisfied, by giving oral or written notice of such delay, extension or termination to the exchange agent; and

• subject to the terms of the registration rights agreement, to amend the terms of any of the exchange offers in any manner. In the event of a material change in any of the exchange offers, including the waiver of a material condition, we will extend the offer period, if necessary, so that at least five business days remain in such offer period following notice of the material change.

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Any delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by oral or written notice to the registered holders of the outstanding notes. If EFH Corp. amends any of the exchange offers in a manner that it determines to constitute a material change, it will promptly disclose the amendment in a manner reasonably calculated to inform the holders of applicable outstanding notes of that amendment.

Conditions to the Exchange Offers

Despite any other term of the exchange offers, EFH Corp. will not be required to accept for exchange, or to issue exchange notes in exchange for, any outstanding notes and it may terminate or amend any of the exchange offers as provided in this prospectus prior to the expiration date if in its reasonable judgment:

• the exchange offers or the making of any exchange by a holder violates any applicable law or interpretation of the SEC; or

• any action or proceeding has been instituted or threatened in writing in any court or by or before any governmental agency with respect to the exchange offers that, in our judgment, would reasonably be expected to impair our ability to proceed with the exchange offers.

In addition, EFH Corp. will not be obligated to accept for exchange the outstanding notes of any holder that has not made to us:

• the representations described under “—Purpose and Effect of the Exchange Offers,” “—Procedures for Tendering Outstanding Notes” and “Plan of Distribution”; or

• any other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to make available to us an appropriate form for registration of the exchange notes under the Securities Act.

EFH Corp. expressly reserves the right at any time or at various times to extend the period of time during which the exchange offers are open. Consequently, EFH Corp. may delay acceptance of any outstanding notes by giving oral or written notice of such extension to their holders. EFH Corp. will return any outstanding notes that it does not accept for exchange for any reason without expense to their tendering holder promptly after the expiration or termination of the exchange offers.

EFH Corp. expressly reserves the right to amend or terminate any of the exchange offers and to reject for exchange any outstanding notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offers specified above. EFH Corp. will give oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the outstanding notes as promptly as practicable. In the case of any extension, such notice will be issued no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date.

These conditions are for our sole benefit, and EFH Corp. may assert them regardless of the circumstances that may give rise to them or waive them in whole or in part at any or at various times prior to the expiration date in our sole discretion. If EFH Corp. fails at any time to exercise any of the foregoing rights, this failure will not constitute a waiver of such right. Each such right will be deemed an ongoing right that it may assert at any time or at various times prior to the expiration date.

In addition, EFH Corp. will not accept for exchange any outstanding notes tendered, and will not issue exchange notes in exchange for any such outstanding notes, if at such time any stop order is threatened or in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture under the Trust Indenture Act of 1939, as amended (the “TIA”).

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Procedures for Tendering Outstanding Notes

To tender your outstanding notes in the exchange offers, you must comply with either of the following:

• complete, sign and date the letter of transmittal, or a facsimile of the letter of transmittal, have the signature(s) on the letter of transmittal guaranteed if required by the letter of transmittal and mail or deliver such letter of transmittal or facsimile thereof to the exchange agent at the address set forth below under “—Exchange Agent” prior to the expiration date; or

• comply with DTC’s Automated Tender Offer Program procedures described below.

In addition, either:

• the exchange agent must receive certificates for outstanding notes along with the letter of transmittal prior to the expiration date;

• the exchange agent must receive a timely confirmation of book-entry transfer of outstanding notes into the exchange agent’s account at DTC according to the procedures for book-entry transfer described below or a properly transmitted agent’s message prior to the expiration date; or

• you must comply with the guaranteed delivery procedures described below.

Your tender, if not withdrawn prior to the expiration date, constitutes an agreement between us and you upon the terms and subject to the conditions described in this prospectus and in the letter of transmittal.

The method of delivery of outstanding notes, letters of transmittal and all other required documents to the exchange agent is at your election and risk. We recommend that instead of delivery by mail, you use an overnight or hand delivery service, properly insured. In all cases, you should allow sufficient time to assure timely delivery to the exchange agent before the expiration date. You should not send letters of transmittal or certificates representing outstanding notes to us. You may request that your broker, dealer, commercial bank, trust company or nominee effect the above transactions for you.

If you are a beneficial owner whose outstanding notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your outstanding notes, you should promptly contact the registered holder and instruct the registered holder to tender on your behalf. If you wish to tender the outstanding notes yourself, you must, prior to completing and executing the letter of transmittal and delivering your outstanding notes, either:

• make appropriate arrangements to register ownership of the outstanding notes in your name; or

• obtain a properly completed bond power from the registered holder of outstanding notes.

The transfer of registered ownership may take considerable time and may not be able to be completed prior to the expiration date.

Signatures on the letter of transmittal or a notice of withdrawal, as the case may be, must be guaranteed by a member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc., a commercial bank or trust company having an office or correspondent in the United States or another “eligible guarantor institution” within the meaning of Rule 17A(d)-15 under the Exchange Act unless the outstanding notes surrendered for exchange are tendered:

• by a registered holder of the outstanding notes who has not completed the box entitled “Special Registration Instructions” or “Special Delivery Instructions” on the letter of transmittal; or

• for the account of an eligible guarantor institution.

If the letter of transmittal is signed by a person other than the registered holder of any outstanding notes listed on the outstanding notes, such outstanding notes must be endorsed or accompanied by a properly

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completed bond power. The bond power must be signed by the registered holder as the registered holder’s name appears on the outstanding notes, and an eligible guarantor institution must guarantee the signature on the bond power.

If the letter of transmittal, any certificates representing outstanding notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, those persons should also indicate when signing and, unless waived by us, they should also submit evidence satisfactory to us of their authority to so act.

The exchange agent and DTC have confirmed that any financial institution that is a participant in DTC’s system may use DTC’s Automated Tender Offer Program to tender outstanding notes. Participants in the program may, instead of physically completing and signing the letter of transmittal and delivering it to the exchange agent, electronically transmit their acceptance of the exchange by causing DTC to transfer the outstanding notes to the exchange agent in accordance with DTC’s Automated Tender Offer Program procedures for transfer. DTC will then send an agent’s message to the exchange agent. The term “agent’s message” means a message transmitted by DTC, received by the exchange agent and forming part of the book-entry confirmation, which states that:

• DTC has received an express acknowledgment from a participant in its Automated Tender Offer Program that is tendering outstanding notes that are the subject of the book-entry confirmation;

• the participant has received and agrees to be bound by the terms of the letter of transmittal, or in the case of an agent’s message relating to guaranteed delivery, that such participant has received and agrees to be bound by the notice of guaranteed delivery; and

• we may enforce that agreement against such participant.

DTC is referred to herein as a “book-entry transfer facility.”

Acceptance of Exchange Notes

In all cases, EFH Corp. will promptly issue exchange notes for outstanding notes that it has accepted for exchange under the exchange offers only after the exchange agent timely receives:

• outstanding notes or a timely book-entry confirmation of such outstanding notes into the exchange agent’s account at the book-entry transfer facility; and

• a properly completed and duly executed letter of transmittal and all other required documents or a properly transmitted agent’s message.

In addition, each broker-dealer that is to receive exchange notes for its own account in exchange for outstanding notes must represent that such outstanding notes were acquired by that broker-dealer as a result of market-making activities or other trading activities and must acknowledge that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the exchange notes. The letters of transmittal state that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. See “Plan of Distribution.”

EFH Corp. will interpret the terms and conditions of the exchange offers, including the letters of transmittal and the instructions to the letters of transmittal, and will resolve all questions as to the validity, form, eligibility, including time of receipt and acceptance of outstanding notes tendered for exchange. Our determinations in this regard will be final and binding on all parties. EFH Corp. reserves the absolute right to reject any and all tenders of any particular outstanding notes not properly tendered or to not accept any particular outstanding notes if the acceptance might, in its or its counsel’s judgment, be unlawful. We also reserve the absolute right to waive any defects or irregularities as to any particular outstanding notes prior to the expiration date.

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Unless waived, any defects or irregularities in connection with tenders of outstanding notes for exchange must be cured within such reasonable period of time as we determine. Neither EFH Corp., the exchange agent nor any other person will be under any duty to give notification of any defect or irregularity with respect to any tender of outstanding notes for exchange, nor will any of them incur any liability for any failure to give notification. Any outstanding notes received by the exchange agent that are not properly tendered and as to which the irregularities have not been cured or waived will be returned by the exchange agent to the tendering holder, unless otherwise provided in the letter of transmittal, promptly after the expiration date.

Book-Entry Delivery Procedures

Promptly after the date of this prospectus, the exchange agent will establish an account with respect to the outstanding notes at DTC and, as the book-entry transfer facility, for purposes of the exchange offers. Any financial institution that is a participant in the book-entry transfer facility’s system may make book-entry delivery of the outstanding notes by causing the book-entry transfer facility to transfer those outstanding notes into the exchange agent’s account at the facility in accordance with the facility’s procedures for such transfer. To be timely, book-entry delivery of outstanding notes requires receipt of a confirmation of a book-entry transfer, a “book-entry confirmation,” prior to the expiration date. In addition, although delivery of outstanding notes may be effected through book-entry transfer into the exchange agent’s account at the book-entry transfer facility, the letter of transmittal or a manually signed facsimile thereof, together with any required signature guarantees and any other required documents, or an “agent’s message,” as defined below, in connection with a book-entry transfer, must, in any case, be delivered or transmitted to and received by the exchange agent at its address set forth on the cover page of the letter of transmittal prior to the expiration date to receive exchange notes for tendered outstanding notes, or the guaranteed delivery procedure described below must be complied with. Tender will not be deemed made until such documents are received by the exchange agent. Delivery of documents to the book-entry transfer facility does not constitute delivery to the exchange agent.

Holders of outstanding notes who are unable to deliver confirmation of the book-entry tender of their outstanding notes into the exchange agent’s account at the book-entry transfer facility or all other documents required by the letter of transmittal to the exchange agent on or prior to the expiration date must tender their outstanding notes according to the guaranteed delivery procedures described below.

Guaranteed Delivery Procedures

If you wish to tender your outstanding notes but your outstanding notes are not immediately available or you cannot deliver your outstanding notes, the letter of transmittal or any other required documents to the exchange agent or comply with the procedures under DTC’s Automatic Tender Offer Program in the case of outstanding notes, prior to the expiration date, you may still tender if:

• the tender is made through an eligible guarantor institution;

• prior to the expiration date, the exchange agent receives from such eligible guarantor institution either a properly completed and duly executed notice of guaranteed delivery, by facsimile transmission, mail, or hand delivery or a properly transmitted agent’s message and notice of guaranteed delivery, that (1) sets forth your name and address, the certificate number(s) of such outstanding notes and the principal amount of outstanding notes tendered; (2) states that the tender is being made thereby; and (3) guarantees that, within three New York Stock Exchange trading days after the expiration date, the letter of transmittal, or facsimile thereof, together with the outstanding notes or a book-entry confirmation, and any other documents required by the letter of transmittal, will be deposited by the eligible guarantor institution with the exchange agent; and

• the exchange agent receives the properly completed and executed letter of transmittal or facsimile thereof, as well as certificate(s) representing all tendered outstanding notes in proper form for transfer or a book-entry confirmation of transfer of the outstanding notes into the exchange agent’s account at DTC and all other documents required by the letter of transmittal within three New York Stock Exchange trading days after the expiration date.

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Upon request, the exchange agent will send to you a notice of guaranteed delivery if you wish to tender your outstanding notes according to the guaranteed delivery procedures.

Withdrawal Rights

Except as otherwise provided in this prospectus, you may withdraw your tender of outstanding notes at any time prior to 11:59 p.m., New York City time, on the expiration date.

For a withdrawal to be effective:

• the exchange agent must receive a written notice, which may be by telegram, telex, facsimile or letter, of withdrawal at its address set forth below under “—Exchange Agent”; or

• you must comply with the appropriate procedures of DTC’s Automated Tender Offer Program system.

Any notice of withdrawal must:

• specify the name of the person who tendered the outstanding notes to be withdrawn;

• identify the outstanding notes to be withdrawn, including the certificate numbers and principal amount of the outstanding notes; and

• where certificates for outstanding notes have been transmitted, specify the name in which such outstanding notes were registered, if different from that of the withdrawing holder.

If certificates for outstanding notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of such certificates, you must also submit:

• the serial numbers of the particular certificates to be withdrawn; and

• a signed notice of withdrawal with signatures guaranteed by an eligible institution unless you are an eligible guarantor institution.

If outstanding notes have been tendered pursuant to the procedures for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at the book-entry transfer facility to be credited with the withdrawn outstanding notes and otherwise comply with the procedures of the facility. We will determine all questions as to the validity, form and eligibility, including time of receipt of notices of withdrawal, and our determination will be final and binding on all parties. Any outstanding notes so withdrawn will be deemed not to have been validly tendered for exchange for purposes of the exchange offers. Any outstanding notes that have been tendered for exchange but that are not exchanged for any reason will be returned to their holder, without cost to the holder, or, in the case of book-entry transfer, the outstanding notes will be credited to an account at the book-entry transfer facility, promptly after withdrawal, rejection of tender or termination of the exchange offers. Properly withdrawn outstanding notes may be retendered by following the procedures described under “—Procedures for Tendering Outstanding Notes” above at any time on or prior to the expiration date.

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Exchange Agent

The Bank of New York Mellon has been appointed as the exchange agent for the exchange offers. The Bank of New York Mellon also acts as trustee under the indenture governing the outstanding notes. You should direct all executed letters of transmittal and all questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery to the exchange agent addressed as follows:

By Registered or Certified Mail:	By Regular Mail:	By Overnight Courier or Hand Delivery:
The Bank of New York Mellon Corporate Trust Operations Reorganization Unit 101 Barclay Street—7 East New York, NY 10286 Attn: Carolle Montreuil	The Bank of New York Mellon Corporate Trust Operations Reorganization Unit 101 Barclay Street—7 East New York, NY 10286 Attn: Carolle Montreuil	The Bank of New York Mellon Corporate Trust Operations Reorganization Unit 101 Barclay Street—7 East New York, NY 10286 Attn: Carolle Montreuil
	By Facsimile Transmission
	(eligible institutions only):
	(212) 298-1915
	To Confirm by Telephone:
	212-815-5920

If you deliver the letter of transmittal to an address other than the one set forth above or transmit instructions via facsimile to a number other than the one set forth above, that delivery or those instructions will not be effective.

Fees and Expenses

The registration rights agreement provides that we will bear all expenses in connection with the performance of our obligations relating to the registration of the exchange notes and the conduct of the exchange offers. These expenses include registration and filing fees, accounting and legal fees and printing costs, among others. We will pay the exchange agent reasonable and customary fees for its services and reasonable out-of-pocket expenses. We will also reimburse brokerage houses and other custodians, nominees and fiduciaries for customary mailing and handling expenses incurred by them in forwarding this prospectus and related documents to their clients that are holders of outstanding notes and for handling or tendering for such clients.

We have not retained any dealer-manager in connection with the exchange offers and will not pay any fee or commission to any broker, dealer, nominee or other person, other than the exchange agent, for soliciting tenders of outstanding notes pursuant to the exchange offers.

Accounting Treatment

We will record the exchange notes in our accounting records at the same carrying value as the outstanding notes, which is the aggregate principal amount as reflected in our accounting records on the date of exchanges. Accordingly, we will not recognize any gain or loss for accounting purposes upon the consummation of the exchange offers.

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Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchanges of outstanding notes under the exchange offers. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if:

• certificates representing outstanding notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be issued in the name of, any person other than the registered holder of outstanding notes tendered;

• tendered outstanding notes are registered in the name of any person other than the person signing the letter of transmittal; or

• a transfer tax is imposed for any reason other than the exchange of outstanding notes under the exchange offers.

If satisfactory evidence of payment of such taxes is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed to that tendering holder.

Holders who tender their outstanding notes for exchange will not be required to pay any transfer taxes. However, holders who instruct us to register exchange notes in the name of, or request that outstanding notes not tendered or not accepted in the exchange offers be returned to, a person other than the registered tendering holder will be required to pay any applicable transfer tax.

Consequences of Failure to Exchange

If you do not exchange your outstanding notes for exchange notes under the exchange offers, your outstanding notes will remain subject to the restrictions on transfer of such outstanding notes:

• as set forth in the legend printed on the outstanding notes as a consequence of the issuance of the outstanding notes pursuant to the exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws; and

• as otherwise set forth in the offering memorandum distributed in connection with the private offerings of the outstanding notes.

In general, you may not offer or sell your outstanding notes unless they are registered under the Securities Act or if the offer or sale is exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the outstanding notes under the Securities Act.

Other

Participating in the exchange offers is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered outstanding notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any outstanding notes that are not tendered in the exchange offers or to file a registration statement to permit resales of any untendered outstanding notes.

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DESCRIPTION OF THE NOTES

General

Certain terms used in this description are defined under the subheading “Certain Definitions.” In this description, (i) the terms “we,” “our” and “us” each refer to Energy Future Holdings Corp. and its consolidated Subsidiaries; and (ii) the term “Issuer” refers only to Energy Future Holdings Corp. and not any of its Subsidiaries.

The Issuer issued $2,000,000,000 aggregate principal amount of 10.875% senior notes due 2017 (the “Cash Pay Notes”) and $2,500,000,000 aggregate principal amount of 11.250%/12.000% optional PIK interest senior notes due 2017 (the “Toggle Notes” and, together with the Cash Pay Notes, the “Notes”) under an Indenture dated as of October 31, 2007 (the “Indenture”) among the Issuer, the Guarantors and The Bank of New York Mellon, as trustee (the “Trustee”). The Notes were issued in a private transaction that was not subject to the registration requirements of the Securities Act. Except as set forth herein, the terms of the Notes are substantially identical and include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act.

As more particularly described under “The Transactions—Ring-Fencing,” upon the consummation of the Merger, Oncor Electric Delivery undertook certain ring-fencing measures to separate itself, its subsidiaries and its immediate parent, Oncor Electric Delivery Holdings, from the Issuer and the Issuer’s other Subsidiaries. Those measures include Oncor Electric Delivery and its Subsidiaries being treated as Unrestricted Subsidiaries with respect to the Notes. As Unrestricted Subsidiaries, the Oncor Subsidiaries are not subject to most of the covenants described herein and have not guaranteed and will not guarantee the Notes.

The Holders of the Notes have acknowledged or, by accepting the Notes, will acknowledge (i) the legal separateness of the Issuer and the Guarantors from Oncor Holdings and the other Oncor Subsidiaries, (ii) that the lenders under the Oncor Electric Delivery Facility and the noteholders under Oncor’s existing debt instruments have likely advanced funds thereunder in reliance upon the separateness of Oncor Holdings and the other Oncor Subsidiaries from the Issuer and the Guarantors, (iii) that Oncor Holdings and the other Oncor Subsidiaries have assets and liabilities that are separate from those of the Issuer and its other Subsidiaries, (iv) that the obligations owing under the Notes are obligations and liabilities of the Issuer and the Guarantors only, and are not the obligations or liabilities of Oncor Holdings or any of the other Oncor Subsidiaries, (v) that the Holders of the Notes shall look solely to the Issuer and the Guarantors and their assets, and not to any assets, or to the pledge of any assets, owned by Oncor Holdings or any of the other Oncor Subsidiaries, for the repayment of any amounts payable pursuant to the Notes and for satisfaction of any other obligations owing to the Holders under the Indenture, the Registration Rights Agreement and any related documents and (vi) that none of Oncor Holdings or any of the other Oncor Subsidiaries shall be personally liable to the Holders of the Notes for any amounts payable, or any other obligation, under the Indenture, the Registration Rights Agreement or any related documents.

The Holders of the Notes have acknowledged and agreed or, by accepting the Notes, will acknowledge and agree that the Holders of the Notes shall not (i) initiate any legal proceeding to procure the appointment of an administrative receiver or (ii) institute any bankruptcy, reorganization, insolvency, winding up, liquidation, or any like proceeding under applicable law, against Oncor Holdings or any of the other Oncor Subsidiaries, or against any of Oncor Holdings’ of the other Oncor Subsidiaries’ assets. The Holders have further acknowledged and agreed and will further acknowledge and agree that Oncor Holdings and each of the other Oncor Subsidiaries is a third party beneficiary of the forgoing covenant and shall have the right to specifically enforce such covenant in any proceeding at law or in equity. The foregoing acknowledgements and agreements are contained in the Indenture.

The following description is only a summary of the material provisions of the Indenture, does not purport to be complete and is qualified in its entirety by reference to the provisions of the Indenture, including the

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definitions therein of certain terms used below. We urge you to read the Indenture because it, and not this description, defines your rights as Holders of the Notes. You may request copies of the Indenture at our address set forth under the heading “Prospectus Summary.”

Brief Description of Notes

The Notes:

• are unsecured senior obligations of the Issuer;

• are effectively subordinated to any secured Indebtedness of the Issuer to the extent of the value of the assets securing such Indebtedness;

• are structurally subordinated to any existing and future indebtedness and liabilities of non-guarantor Subsidiaries, including the Oncor Subsidiaries, TCEH and the TCEH Subsidiaries, any of the Issuer’s Foreign Subsidiaries and any Unrestricted Subsidiaries;

• rank equally in right of payment with all existing and future unsecured Senior Indebtedness of the Issuer (including the applicable Existing Notes);

• are senior in right of payment to any future Subordinated Indebtedness of the Issuer;

• are initially unconditionally guaranteed on a joint and several and senior basis only by Energy Future Competitive Holdings and Energy Future Intermediate Holding.

Guarantees

The Guarantors, as primary obligors and not merely as sureties, initially jointly and severally fully and unconditionally guaranteed, on a senior basis, the performance and full and punctual payment when due, whether at maturity, by acceleration or otherwise, of all obligations of the Issuer under the Indenture and the Notes, whether for payment of principal of, premium, if any, or interest in respect of the Notes, expenses, indemnification or otherwise, on the terms set forth in the Indenture by executing the Indenture.

Only Energy Future Competitive Holdings and Energy Future Intermediate Holding initially guaranteed the Notes. Each of the Guarantees of the Notes is a general unsecured senior obligation of each Guarantor. The Guarantees rank equally in right of payment with all existing and future Senior Indebtedness of the Guarantor and is effectively subordinated to all Secured Indebtedness of such Guarantor to the extent of the value of the collateral securing such Indebtedness. The Guarantees are senior in right of payment to all existing and future Subordinated Indebtedness of each Guarantor. The Notes are structurally subordinated to Indebtedness and other liabilities of Subsidiaries of the Issuer that do not Guarantee the Notes.

Not all of the Issuer’s Subsidiaries guaranteed the Notes. In the event of a bankruptcy, liquidation or reorganization of any of these non-guarantor Subsidiaries, the non-guarantor Subsidiaries will pay the holders of their debt and their trade creditors before they will be able to distribute any of their assets to the Issuer. None of TCEH, the TCEH Subsidiaries, or the Oncor Subsidiaries guaranteed the Notes. For the year ended December 31, 2007 and the nine months ended September 30, 2008, the non-guarantor Subsidiaries generated all of the Issuer’s consolidated total revenue. In addition, as of September 30, 2008, the non-guarantor Subsidiaries held substantially all of the Issuer’s consolidated total assets.

The obligations of each Guarantor under its Guarantee is limited as necessary to prevent the Guarantee from constituting a fraudulent conveyance under applicable law.

Any entity that makes a payment under its Guarantee is entitled upon payment in full of all guaranteed obligations under the Indenture to a contribution from each other Guarantor in an amount equal to such other Guarantor’s pro rata portion of such payment based on the respective net assets of all the Guarantors at the time of such payment determined in accordance with GAAP.

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If a Guarantee were rendered voidable, it could be subordinated by a court to all other indebtedness (including guarantees and other contingent liabilities) of the Guarantor, and, depending on the amount of such indebtedness, a Guarantor’s liability on its Guarantee could be reduced to zero. See “Risk Factors—Risks Relating to the Notes—Federal and state statutes allow courts, under specific circumstances, to void guarantees, subordinate claims in respect of guarantees and require note holders to return payments received from the guarantors.”

Each Guarantee by a Guarantor provides by its terms that it will be automatically and unconditionally released and discharged upon:

(1)(a) any sale, exchange or transfer (by merger or otherwise) of the Capital Stock of such Guarantor (including any sale, exchange or transfer), after which the applicable Guarantor is no longer a Restricted Subsidiary or sale of all or substantially all the assets of such Guarantor, which sale, exchange or transfer is made in compliance with the applicable provisions of the Indenture;

(b) the release or discharge of the guarantee by such Guarantor that resulted in the creation of such Guarantee, except a discharge or release by or as a result of payment under such guarantee;

(c) the designation of any Restricted Subsidiary that is a Guarantor as an Unrestricted Subsidiary in compliance with the applicable provisions of the Indenture; or

(d) the exercise by the Issuer of its legal defeasance option or covenant defeasance option as described under “Legal Defeasance and Covenant Defeasance” or the discharge of the Issuer’s obligations under the Indenture in accordance with the terms of the Indenture; and

(2) such Guarantor delivering to the Trustee an Officer’s Certificate and an Opinion of Counsel, each stating that all conditions precedent provided for in the Indenture relating to such transaction have been complied with.

Holding Company Structure

The Issuer is a holding company for its Subsidiaries, with no material operations of its own and only limited assets. Accordingly, the Issuer is dependent upon the distribution of the earnings of its Subsidiaries, whether in the form of dividends, advances or payments on account of intercompany obligations, to service its debt obligations.

Paying Agent and Registrar for the Notes

The Issuer will maintain one or more paying agents for the Notes in the Borough of Manhattan, City of New York. The initial paying agent for the Notes is the Trustee.

The Issuer also maintains a registrar with offices in the Borough of Manhattan, City of New York. The initial registrar is the Trustee. The registrar will maintain a register reflecting ownership of the Notes outstanding from time to time and will make payments on and facilitate transfer of Notes on behalf of the Issuer.

The Issuer may change the paying agents or the registrars without prior notice to the Holders. The Issuer or any of its Subsidiaries may act as a paying agent or registrar.

Transfer and Exchange

A Holder may transfer or exchange Notes in accordance with the Indenture. The registrar and the Trustee may require a Holder to furnish appropriate endorsements and transfer documents in connection with a transfer of Notes. Holders will be required to pay all taxes due on transfer. The Issuer will not be required to transfer or exchange any Note selected for redemption. Also, the Issuer will not be required to transfer or exchange any Note for a period of 15 days before a selection of Notes to be redeemed.

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Principal, Maturity and Interest

The Issuer issued $4,500,000,000 in aggregate principal amount of Notes, of which $2,000,000,000 in aggregate principal amount were Cash Pay Notes and $2,500,000,000 in aggregate principal amount were Toggle Notes. The Notes will mature on November 1, 2017. On May 1, 2017, the Issuer shall repay in full in U.S. Dollars an amount of Toggle Notes equal to $50,000,000, which shall be made on a pro rata basis based on the aggregate principal amount of Toggle Notes outstanding. Subject to compliance with the covenant described below under “—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock,” the Issuer may issue additional Cash Pay Notes and/or Toggle Notes from time to time under the Indenture (any such Cash Pay Notes or Toggle Notes, “Additional Notes”). In addition, in connection with the payment of PIK Interest (as defined below) or Partial PIK Interest (as defined below) in respect of the Toggle Notes, the Issuer is entitled to, without the consent of the Holders, increase the outstanding principal amount of the Toggle Notes or issue additional Toggle Notes (the “PIK Notes”) under the Indenture on the same terms and conditions as the Toggle Notes (in each case, the “PIK Payment”). The Cash Pay Notes and the Toggle Notes are each a separate series of Notes but are treated as a single class of securities under the Indenture, except as otherwise stated herein. As a result, Holders of each series of Notes have no separate rights to, among other things, give notice of Defaults or to direct the Trustee to exercise remedies during an Event of Default or otherwise. Except as described under “—Amendment, Supplement and Waiver,” the Notes, the PIK Notes and any Additional Notes subsequently issued under the Indenture will be treated as a single class for all purposes under the Indenture, including waivers, amendments, redemptions and offers to purchase.

Cash Pay Notes

Interest on the Cash Pay Notes accrues at the rate of 10.875% per annum and is payable semi-annually in arrears on May 1 and November 1 to the Holders of Cash Pay Notes of record on the immediately preceding April 15 and October 15. Interest on the Cash Pay Notes accrues from the most recent date to which interest has been paid or, if no interest has been paid, from and including the Issue Date. Interest on the Cash Pay Notes is computed on the basis of a 360-day year comprised of twelve 30-day months.

Toggle Notes

Interest on the Toggle Notes is payable semi-annually in arrears on May 1 and November 1 of each year to the Holders of Toggle Notes of record on the immediately preceding April 15 and October 15. Interest on the Toggle Notes accrues from the most recent date to which interest has been paid or, if no interest has been paid, from and including the Issue Date. Interest on the Toggle Notes is computed on the basis of a 360-day year comprised of twelve 30-day months.

For any interest payment period after the initial interest payment period and prior to November 1, 2012, the Issuer may, at its option, elect to pay interest on the Toggle Notes:

• entirely in cash (“Cash Interest”);

• entirely by increasing the principal amount of the outstanding Toggle Notes or by issuing PIK Notes (“PIK Interest”); or

• on 50% of the outstanding principal amount of the Toggle Notes in cash and on 50% of the principal amount by increasing the principal amount of the outstanding Toggle Notes or by issuing PIK Notes (“Partial PIK Interest”).

The Issuer must elect the form of interest payment for the Toggle Notes with respect to each interest period by delivering a notice to the Trustee prior to the beginning of each interest period. The Trustee shall promptly deliver a corresponding notice to the Holders. In the absence of such an election for any interest period, interest on the Toggle Notes shall be payable according to the election for the previous interest period. After November 1, 2012, the Issuer will make all interest payments on the Toggle Notes entirely in cash.

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Notwithstanding anything to the contrary, the payment of accrued interest in connection with any redemption of Toggle Notes as described under “—Optional Redemption—Toggle Notes” or “—Repurchase at the Option of Holders” shall be made solely in cash.

Cash Interest on the Toggle Notes accrues at a rate of 11.250% per annum and be payable in cash. PIK Interest on the Toggle Notes accrues at a rate of 12.000% per annum and be payable (x) with respect to Toggle Notes represented by one or more global notes registered in the name of, or held by, The Depository Trust Company (“DTC”) or its nominee on the relevant record date, by increasing the principal amount of the outstanding global Toggle Note by an amount equal to the amount of PIK Interest for the applicable interest period (rounded up to the nearest $1,000) (or, if necessary, pursuant to the requirements of DTC, to authenticate new global Toggle Notes executed by the Issuer with such increased principal amounts) and (y) with respect to Toggle Notes represented by certificated notes, by issuing PIK Notes in certificated form in an aggregate principal amount equal to the amount of PIK Interest for the applicable period (rounded up to the nearest whole dollar), and the Trustee will, at the request of the Issuer, authenticate and deliver such PIK Notes in certificated form for original issuance to the Holders on the relevant record date, as shown by the records of the register of Holders. In the event that the Issuer elects to pay Partial PIK Interest for any interest period, each Holder will be entitled to receive Cash Interest in respect of 50% of the principal amount of the Toggle Notes held by such Holder on the relevant record date and PIK Interest in respect of 50% of the principal amount of the Toggle Notes held by such Holder on the relevant record date. Following an increase in the principal amount of the outstanding global Toggle Notes as a result of a PIK Payment, the global Toggle Notes will bear interest on such increased principal amount from and after the date of such PIK Payment. Any PIK Notes issued in certificated form will be dated as of the applicable interest payment date and will bear interest from and after such date. All Toggle Notes issued pursuant to a PIK Payment will be governed by, and subject to the terms, provisions and conditions of, the Indenture and shall have the same rights and benefits as the Toggle Notes issued on the Issue Date. Any certificated PIK Notes will be issued with the description PIK on the face of such PIK Note.

In October 2008, the Issuer delivered a notice to the Trustee of its election to make the May 1, 2009 interest payment on the Toggle Notes entirely using PIK Interest.

Unless the context requires otherwise, references to “Notes” for all purposes of the Indenture and this “Description of the Notes” section include any PIK Notes and Additional Notes that are actually issued, and references to “principal amount” of the Notes includes any increase in the principal amount of the outstanding Notes as a result of a PIK Payment.

Principal of, premium, if any, and interest on the Notes will be payable at the office or agency of the Issuer maintained for such purpose within the City and State of New York or, at the option of the Issuer, payment of interest may be made by check mailed to the Holders of the Notes at their respective addresses set forth in the register of Holders; provided that all payments of principal, premium, if any, and interest with respect to the Notes represented by one or more global notes registered in the name of or held by DTC or its nominee will be made by wire transfer of immediately available funds to the accounts specified by the Holder or Holders thereof. Until otherwise designated by the Issuer, the Issuer’s office or agency in New York will be the office of the Trustee maintained for such purpose.

Mandatory Redemption; Offers to Purchase; Open Market Purchases

Except as set forth under “—Principal, Interest and Maturity” above, the Issuer is not required to make any mandatory redemption or sinking fund payments with respect to the Notes. However, under certain circumstances, the Issuer may be required to offer to purchase Notes as described under the caption “—Repurchase at the Option of Holders.” The Issuer may at any time and from time to time purchase Notes in the open market or otherwise.

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Optional Redemption

Cash Pay Notes

Except as set forth below, the Issuer is not entitled to redeem Cash Pay Notes at its option prior to November 1, 2012.

At any time prior to November 1, 2012, the Issuer may redeem all or a part of the Cash Pay Notes, upon not less than 30 nor more than 60 days’ prior notice mailed by first-class mail to the registered address of each Holder of Cash Pay Notes or otherwise in accordance with the procedures of DTC, at a redemption price equal to 100% of the principal amount of the Cash Pay Notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest to the date of redemption (the “Redemption Date”), subject to the rights of Holders of Cash Pay Notes on the relevant record date to receive interest due on the relevant interest payment date.

On and after November 1, 2012, the Issuer may redeem the Cash Pay Notes, in whole or in part, upon not less than 30 nor more than 60 days’ prior notice mailed by first-class mail to the registered address of each Holder of Cash Pay Notes or otherwise in accordance with the procedures of DTC, at the redemption prices (expressed as percentages of principal amount of the Cash Pay Notes to be redeemed) set forth below, plus accrued and unpaid interest thereon to the applicable Redemption Date, subject to the right of Holders of Cash Pay Notes of record on the relevant record date to receive interest due on the relevant interest payment date, if redeemed during the twelve-month period beginning on November 1 of each of the years indicated below:

Year	Percentage
2012	105.438	%
2013	103.625	%
2014	101.813	%
2015 and thereafter	100.000	%

In addition, until November 1, 2010, the Issuer may, at its option, on one or more occasions redeem up to 35% of the aggregate principal amount of Cash Pay Notes at a redemption price equal to 110.875% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon to the applicable Redemption Date, subject to the right of Holders of Cash Pay Notes of record on the relevant record date to receive interest due on the relevant interest payment date, with the net cash proceeds of one or more Equity Offerings; provided that at least 50% of the sum of the original aggregate principal amount of Cash Pay Notes issued under the Indenture and the original principal amount of any Additional Notes that are Cash Pay Notes issued under the Indenture after the Issue Date remains outstanding immediately after the occurrence of each such redemption; provided further that each such redemption occurs within 90 days of the date of closing of each such Equity Offering.

Any notice of any redemption may be given prior to the redemption thereof, and any such redemption or notice may, at the Issuer’s discretion, be subject to one or more conditions precedent, including, but not limited to, completion of an Equity Offering or other corporate transaction.

If the Issuer redeems less than all of the outstanding Cash Pay Notes, the Trustee shall select the Cash Pay Notes to be redeemed in the manner described under “—Repurchase at the Option of Holders—Selection and Notice.”

Toggle Notes

Except as set forth below, the Issuer is not entitled to redeem Toggle Notes at its option prior to November 1, 2012.

At any time prior to November 1, 2012, the Issuer may redeem all or a part of the Toggle Notes, upon not less than 30 nor more than 60 days’ prior notice mailed by first-class mail to the registered address of each

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Holder of Toggle Notes or otherwise in accordance with the procedures of DTC, at a redemption price equal to 100% of the principal amount of the Toggle Notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest to the Redemption Date, subject to the rights of Holders of Toggle Notes on the relevant record date to receive interest due on the relevant interest payment date.

On and after November 1, 2012, the Issuer may redeem the Toggle Notes, in whole or in part, upon not less than 30 nor more than 60 days’ prior notice mailed by first-class mail to the registered address of each Holder of Toggle Notes or otherwise in accordance with the procedures of DTC, at the redemption prices (expressed as percentages of principal amount of the Toggle Notes to be redeemed) set forth below, plus accrued and unpaid interest thereon to the applicable Redemption Date, subject to the right of Holders of Toggle Notes of record on the relevant record date to receive interest due on the relevant interest payment date, if redeemed during the twelve-month period beginning on November 1 of each of the years indicated below:

Year	Percentage
2012	105.625	%
2013	103.750	%
2014	101.875	%
2015 and thereafter	100.000	%

In addition, until November 1, 2010, the Issuer may, at its option, on one or more occasions redeem up to 35% of the aggregate principal amount of Toggle Notes at a redemption price equal to 111.250% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon to the applicable Redemption Date, subject to the right of Holders of Toggle Notes of record on the relevant record date to receive interest due on the relevant interest payment date, with the net cash proceeds of one or more Equity Offerings; provided that at least 50% of the sum of the original aggregate principal amount of Toggle Notes issued under the Indenture and the original principal amount of any Additional Notes that are Toggle Notes issued under the Indenture after the Closing Date remains outstanding immediately after the occurrence of each such redemption; provided further that each such redemption occurs within 90 days of the date of closing of each such Equity Offering.

At the end of any “accrual period” (as defined in Section 1272(a)(5) of the Code) ending after the fifth anniversary of the Issue Date (each, an “Optional Interest Repayment Date”), the Issuer may pay in cash, without duplication, all accrued and unpaid interest, if any, and all accrued but unpaid “original issue discount” (as defined in Section 1273(a)(1) of the Code) on each Toggle Note then outstanding up to, in the aggregate, the Optional Interest Repayment Amount (each such redemption, an “Optional Interest Repayment”). The “Optional Interest Repayment Amount” shall mean, as of each Optional Interest Repayment Date, the excess, if any, of (a) the aggregate amount of accrued and unpaid interest and all accrued and unpaid “original issue discount” (as defined in Section 1273(a)(1) of the Code) with respect to the Toggle Notes, over (b) an amount equal to the product of (i) the “issue price” (as defined in Sections 1273(b) and 1274(a) of the Code) of the Toggle Notes multiplied by (ii) the “yield to maturity” (as defined in the Treasury Regulation Section 1.1272-1(b)(1)(i)) of the Toggle Notes, minus (c) $50,000,000.

Any notice of any redemption may be given prior to the redemption thereof, and any such redemption or notice may, at the Issuer’s discretion, be subject to one or more conditions precedent, including, but not limited to, completion of an Equity Offering or other corporate transaction.

If the Issuer redeems less than all of the outstanding Toggle Notes, the Trustee shall select the Toggle Notes to be redeemed in the manner described under “—Repurchase at the Option of Holders—Selection and Notice.”

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Repurchase at the Option of Holders

Change of Control

The Notes provide that if a Change of Control occurs, unless the Issuer has previously or concurrently mailed a redemption notice with respect to all the outstanding Notes as described under “Optional Redemption” and will redeem all of the outstanding Notes pursuant thereto, the Issuer will make an offer to purchase all of the Notes pursuant to the offer described below (the “Change of Control Offer”) at a price in cash (the “Change of Control Payment”) equal to 101% of the aggregate principal amount thereof plus accrued and unpaid interest to the date of purchase, subject to the right of Holders of the Notes of record on the relevant record date to receive interest due on the relevant interest payment date. Within 30 days following any Change of Control, the Issuer will send notice of such Change of Control Offer by first-class mail, with a copy to the Trustee, to each Holder of Notes to the address of such Holder appearing in the security register with a copy to the Trustee or otherwise in accordance with the procedures of DTC, with the following information:

(1) that a Change of Control Offer is being made pursuant to the covenant entitled “Change of Control” and that all Notes properly tendered pursuant to such Change of Control Offer will be accepted for payment by the Issuer;

(2) the purchase price and the purchase date, which will be no earlier than 30 days nor later than 60 days from the date such notice is mailed (the “Change of Control Payment Date”);

(3) that any Note not properly tendered will remain outstanding and continue to accrue interest;

(4) that unless the Issuer defaults in the payment of the Change of Control Payment, all Notes accepted for payment pursuant to the Change of Control Offer will cease to accrue interest on the Change of Control Payment Date;

(5) that Holders electing to have any Notes purchased pursuant to a Change of Control Offer will be required to surrender such Notes, with the form entitled “Option of Holder to Elect Purchase” on the reverse of such Notes completed, to the paying agent specified in the notice at the address specified in the notice prior to the close of business on the third Business Day preceding the Change of Control Payment Date;

(6) that Holders will be entitled to withdraw their tendered Notes and their election to require the Issuer to purchase such Notes; provided that the paying agent receives, not later than the close of business on the expiration date of the Change of Control Offer, a telegram, facsimile transmission or letter setting forth the name of the Holder of the Notes, the principal amount of Notes tendered for purchase, and a statement that such Holder is withdrawing its tendered Notes and its election to have such Notes purchased;

(7) that the Holders whose Notes are being repurchased only in part will be issued new Notes and such new Notes will be equal in principal amount to the unpurchased portion of the Notes surrendered. The unpurchased portion of the Notes must be equal to $2,000 or an integral multiple of $1,000 in excess thereof; and

(8) the other instructions, as determined by the Issuer, consistent with the covenant described hereunder, that a Holder must follow.

The Issuer will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws or regulations are applicable in connection with the repurchase of Notes pursuant to a Change of Control Offer. To the extent that the provisions of any securities laws or regulations conflict with the provisions of the Indenture, the Issuer will comply with the applicable securities laws and regulations and shall not be deemed to have breached its obligations described in the Indenture by virtue thereof.

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On the Change of Control Payment Date, the Issuer will, to the extent permitted by law,

(1) accept for payment all Notes issued by it or portions thereof properly tendered pursuant to the Change of Control Offer;

(2) deposit with the paying agent an amount equal to the aggregate Change of Control Payment in respect of all Notes or portions thereof so tendered; and

(3) deliver, or cause to be delivered, to the Trustee for cancellation the Notes so accepted together with an Officer’s Certificate to the Trustee stating that such Notes or portions thereof have been tendered to and purchased by the Issuer.

The TCEH Senior Secured Facilities, and future credit agreements or other agreements relating to Senior Indebtedness to which the Issuer becomes a party may, provide that certain change of control events with respect to the Issuer would constitute a default thereunder (including a Change of Control under the Indenture). If we experience a change of control that triggers a default under the TCEH Senior Secured Facilities, we could seek a waiver of such default or seek to refinance the TCEH Senior Secured Facilities. In the event we do not obtain such a waiver or refinance the TCEH Senior Secured Facilities, such default could result in amounts outstanding under the TCEH Senior Secured Facilities being declared due and payable and could cause our Receivables Facility to be wound down.

Our ability to pay cash to the Holders of Notes following the occurrence of a Change of Control may be limited by our then-existing financial resources. Therefore, sufficient funds may not be available when necessary to make any required repurchases.

The Change of Control purchase feature of the Notes may in certain circumstances make more difficult or discourage a sale or takeover of us and, thus, the removal of incumbent management. The Change of Control purchase feature is a result of negotiations between the Initial Purchasers and us. We have no present intention to engage in a transaction involving a Change of Control, although it is possible that we could decide to do so in the future. Subject to the limitations discussed below, we could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the Indenture, but that could increase the amount of indebtedness outstanding at such time or otherwise affect our capital structure or credit ratings. Restrictions on our ability to incur additional Indebtedness are contained in the covenants described under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “Certain Covenants—Liens.” Such restrictions in the Indenture can be waived with the consent of the Holders of a majority in principal amount of the outstanding Notes. Except for the limitations contained in such covenants, however, the Indenture does not contain any covenants or provisions that may afford Holders of the Notes protection in the event of a highly leveraged transaction.

The Issuer will not be required to make a Change of Control Offer following a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by us and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer. Notwithstanding anything to the contrary herein, a Change of Control Offer may be made in advance of a Change of Control, conditional upon such Change of Control, if a definitive agreement is in place for the Change of Control at the time of making of the Change of Control Offer.

The definition of “Change of Control” includes a disposition of all or substantially all of the assets of the Issuer to any Person. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve a disposition of “all or substantially all” of the assets of the Issuer. As a result, it may be unclear as to whether a Change of Control has occurred and whether a Holder of Notes may require the Issuer to make an offer to repurchase the Notes as described above.

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The provisions under the Indenture relating to the Issuer’s obligation to make an offer to repurchase the Notes as a result of a Change of Control may be waived or modified with the written consent of the Holders of a majority in principal amount of the outstanding Notes.

Asset Sales

The Indenture provides that the Issuer will not, and will not permit any of its Restricted Subsidiaries to consummate, directly or indirectly, an Asset Sale, unless:

(1) the Issuer or such Restricted Subsidiary, as the case may be, receives consideration at the time of such Asset Sale at least equal to the fair market value (as determined in good faith by the Issuer) of the assets sold or otherwise disposed of; and

(2) except in the case of a Permitted Asset Swap, at least 75% of the consideration therefor received by the Issuer or such Restricted Subsidiary, as the case may be, is in the form of cash or Cash Equivalents; provided that the amount of:

(a) any liabilities (as shown on the Issuer’s or such Restricted Subsidiary’s most recent balance sheet or in the footnotes thereto) of the Issuer or such Restricted Subsidiary, other than liabilities that are by their terms subordinated to the Notes or that are owed to the Issuer or an Affiliate of the Issuer, that are assumed by the transferee of any such assets and for which the Issuer and all of its Restricted Subsidiaries have been validly released by all applicable creditors in writing,

(b) any securities received by the Issuer or such Restricted Subsidiary from such transferee that are converted by the Issuer or such Restricted Subsidiary into cash (to the extent of the cash received) within 180 days following the closing of such Asset Sale, and

(c) any Designated Non-cash Consideration received by the Issuer or such Restricted Subsidiary in such Asset Sale having an aggregate fair market value, taken together with all other Designated Non-cash Consideration received pursuant to this clause (c) that is at that time outstanding, not to exceed 5% of Total Assets at the time of the receipt of such Designated Non-cash Consideration, with the fair market value of each item of Designated Non-cash Consideration being measured at the time received and without giving effect to subsequent changes in value,

shall be deemed to be cash for purposes of this provision and for no other purpose.

Within 450 days after the receipt of any Net Proceeds of any Asset Sale, the Issuer or such Restricted Subsidiary, at its option, may apply the Net Proceeds from such Asset Sale,

(1) to permanently reduce:

(a) Obligations under Senior Indebtedness which is Secured Indebtedness permitted by the Indenture, and to correspondingly reduce commitments with respect thereto;

(b) Obligations under other Senior Indebtedness (and to correspondingly reduce commitments with respect thereto); provided that the Issuer shall equally and ratably reduce Obligations under the Notes as provided under “Optional Redemption,” through open-market purchases (to the extent such purchases are at or above 100% of the principal amount thereof) or otherwise by making an offer (in accordance with the procedures set forth below for an Asset Sale Offer) to all Holders to purchase their Notes at 100% of the principal amount thereof, plus the amount of accrued but unpaid interest, if any;

(c) Obligations under the Existing Notes which have a final maturity date (as in effect on the Closing Date) on or prior to October 15, 2017, provided that, at the time of, and after giving effect to, such repurchase, redemption or defeasance, the aggregate amount of Net Proceeds used to repurchase, redeem or defease Existing Notes pursuant to this subclause (c) following the Closing Date shall not exceed 3.5% of Total Assets at such time; or

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(d) Indebtedness of a Restricted Subsidiary that is not a Guarantor, other than Indebtedness owed to the Issuer or another Restricted Subsidiary (or any affiliate thereof);

provided that, if an offer to purchase any Indebtedness of TCEH or any of its Restricted Subsidiaries is made in accordance with the terms of such Indebtedness, the obligation to permanently reduce Indebtedness of a Restricted Subsidiary will be deemed to be satisfied to the extent of the amount of the offer, whether or not accepted by the holders thereof, and no Net Proceeds in the amount of such offer will be deemed to exist following such offer;

(2) to make (a) an Investment in any one or more businesses; provided that such Investment in any business is in the form of the acquisition of Capital Stock and results in the Issuer or another of its Restricted Subsidiaries, as the case may be, owning an amount of the Capital Stock of such business such that it constitutes a Restricted Subsidiary, (b) capital expenditures or (c) acquisitions of other assets, in each of (a), (b) and (c), used or useful in a Similar Business; or

(3) to make an Investment in (a) any one or more businesses; provided that such Investment in any business is in the form of the acquisition of Capital Stock and results in the Issuer or another of its Restricted Subsidiaries, as the case may be, owning an amount of the Capital Stock of such business such that it constitutes a Restricted Subsidiary, (b) properties or (c) acquisitions of other assets that, in each of (a), (b) and (c), replace the businesses, properties and/or assets that are the subject of such Asset Sale;

provided that, in the case of clauses (2) and (3) above, a binding commitment shall be treated as a permitted application of the Net Proceeds from the date of such commitment so long as the Issuer, or such other Restricted Subsidiary enters into such commitment with the good faith expectation that such Net Proceeds will be applied to satisfy such commitment within 180 days of such commitment (an “Acceptable Commitment”) (and reinvest within the later of 450 days from the date of receipt of Net Proceeds and 180 days of receipt of such commitment), and, in the event any Acceptable Commitment is later cancelled or terminated for any reason before the Net Proceeds are applied in connection therewith, the Issuer or such Restricted Subsidiary enters into another Acceptable Commitment (a “Second Commitment”) within the later of (a) 180 days of such cancellation or termination or (b) the initial 450-day period; provided further, that if any Second Commitment is later cancelled or terminated for any reason before such Net Proceeds are applied, then such Net Proceeds shall constitute Excess Proceeds.

Notwithstanding the preceding paragraph, in the event that regulatory approval is necessary for an asset or investment, or replacement, repair or restoration on any asset or investment, then the Issuer or any Restricted Subsidiary shall have an additional 365 days to apply the Net Proceeds from such Asset Sale in accordance with the preceding paragraph.

Any Net Proceeds from Asset Sales that are not invested or applied as provided and within the time period set forth in the first sentence of the second preceding paragraph will be deemed to constitute “Excess Proceeds.” When the aggregate amount of Excess Proceeds exceeds $200.0 million, the Issuer shall make an offer to all Holders of the Notes and, if required or permitted by the terms of any Senior Indebtedness, to the holders of such Senior Indebtedness (an “Asset Sale Offer”), to purchase the maximum aggregate principal amount of the Notes and such Senior Indebtedness that is a minimum of $2,000 or an integral multiple of $1,000 in excess thereof that may be purchased out of the Excess Proceeds at an offer price in cash in an amount equal to 100% of the principal amount thereof, plus accrued and unpaid interest to the date fixed for the closing of such offer, in accordance with the procedures set forth in the Indenture. The Issuer will commence an Asset Sale Offer with respect to Excess Proceeds within 10 Business Days after the date that Excess Proceeds exceed $200.0 million by mailing the notice required pursuant to the terms of the Indenture, with a copy to the Trustee.

To the extent that the aggregate amount of Notes and such Senior Indebtedness tendered pursuant to an Asset Sale Offer is less than the Excess Proceeds, the Issuer may use any remaining Excess Proceeds for general corporate purposes, subject to other covenants contained in the Indenture. If the aggregate principal amount of Notes or the Senior Indebtedness surrendered by such holders thereof exceeds the amount of Excess Proceeds,

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the Trustee shall select the Notes and such Senior Indebtedness to be purchased on a pro rata basis based on the accreted value or principal amount of the Notes or such Senior Indebtedness tendered. Additionally, the Issuer may, at its option, make an Asset Sale Offer using proceeds from any Asset Sale at any time after consummation of such Asset Sale; provided that such Asset Sale Offer shall be in an aggregate amount of not less than $25.0 million. Upon consummation of such Asset Sale Offer, any Net Proceeds not required to be used to purchase Notes shall not be deemed Excess Proceeds.

Pending the final application of any Net Proceeds pursuant to this covenant, the holder of such Net Proceeds may apply such Net Proceeds temporarily to reduce Indebtedness outstanding under a revolving credit facility or otherwise invest such Net Proceeds in any manner not prohibited by the Indenture.

The Issuer will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws or regulations are applicable in connection with the repurchase of the Notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the provisions of the Indenture, the Issuer will comply with the applicable securities laws and regulations and shall not be deemed to have breached its obligations described in the Indenture by virtue thereof.

Selection and Notice

If the Issuer is redeeming less than all of the Notes issued by it at any time, the Trustee will select the Notes to be redeemed (a) if the Notes are listed on any national securities exchange, in compliance with the requirements of the principal national securities exchange on which the Notes are listed, (b) on a pro rata basis to the extent practicable or (c) by lot or such other similar method in accordance with the procedures of DTC. No Notes of $2,000 or less can be redeemed in part.

Notices of purchase or redemption shall be mailed by first-class mail, postage prepaid, at least 30 but not more than 60 days before the purchase or Redemption Date to each Holder of Notes at such Holder’s registered address or otherwise in accordance with the procedures of DTC, except that redemption notices may be mailed more than 60 days prior to a Redemption Date if the notice is issued in connection with a defeasance of the Notes or a satisfaction and discharge of the Indenture. If any Note is to be purchased or redeemed in part only, any notice of purchase or redemption that relates to such Note shall state the portion of the principal amount thereof that has been or is to be purchased or redeemed. The notice will also state any conditions applicable to a redemption.

The Issuer will issue a new Note in a principal amount equal to the unredeemed portion of the original Note in the name of the Holder upon cancellation of the original Note. Notes called for redemption become due on the date fixed for redemption but such redemption may be subject to one or more conditions precedent. On and after the Redemption Date, interest ceases to accrue on Notes or portions thereof called for redemption.

Certain Covenants

Limitation on Restricted Payments

The Issuer will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(I) declare or pay any dividend or make any payment or distribution on account of the Issuer’s, or any of its Restricted Subsidiaries’ Equity Interests, including any dividend or distribution payable in connection with any merger or consolidation other than:

(a) dividends or distributions by the Issuer payable solely in Equity Interests (other than Disqualified Stock) of the Issuer; or

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(b) dividends or distributions by a Restricted Subsidiary so long as, in the case of any dividend or distribution payable on or in respect of any class or series of securities issued by a Restricted Subsidiary other than a Wholly-Owned Subsidiary, the Issuer or a Restricted Subsidiary receives at least its pro rata share of such dividend or distribution in accordance with its Equity Interests in such class or series of securities;

(II) purchase, redeem, defease or otherwise acquire or retire for value any Equity Interests of the Issuer or any direct or indirect parent of the Issuer, including in connection with any merger or consolidation;

(III) make any principal payment on, or redeem, repurchase, defease or otherwise acquire or retire for value in each case, prior to any scheduled repayment, sinking fund payment or maturity, any Subordinated Indebtedness, other than:

(a) Indebtedness permitted under clauses (7) and (8) of the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”; or

(b) the purchase, repurchase or other acquisition of Subordinated Indebtedness purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of purchase, repurchase or acquisition; or

(IV) make any Restricted Investment

(all such payments and other actions set forth in clauses (I) through (IV) above (other than any exception thereto) being collectively referred to as “Restricted Payments”), unless, at the time of such Restricted Payment:

(1) no Default shall have occurred and be continuing or would occur as a consequence thereof;

(2)(A) with respect to any Restricted Payment by the Issuer or any Restricted Subsidiary of the Issuer (other than TCEH and its Restricted Subsidiaries) immediately after giving effect to such transaction on a pro forma basis, the Restricted Payment Coverage Ratio for the most recently ended four fiscal quarters for which internal financial statements are available immediately preceding the date of such Restricted Payment would have been at least 2.00 to 1.00 or (B) with respect to a Restricted Payment by TCEH or any Restricted Subsidiary of TCEH, immediately after giving effect to such transaction on a pro forma basis, TCEH could incur at least $1.00 of additional Indebtedness under the provisions of clause (ii) of the first paragraph of the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”; and

(3) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Issuer and its Restricted Subsidiaries after the Closing Date (including Restricted Payments permitted by clauses (1), (2) (with respect to the payment of dividends on Refunding Capital Stock (as defined below) pursuant to clause (b) thereof only), (6)(c), (9) and (14) of the next succeeding paragraph, but excluding all other Restricted Payments permitted by the next succeeding paragraph), is less than the sum of (without duplication):

(a)(A) with respect to a Restricted Payment by the Issuer or any Restricted Subsidiary of the Issuer (other than TCEH and its Restricted Subsidiaries) 50% of the Consolidated Net Income of the Issuer for the period (taken as one accounting period) beginning October 1, 2007, to the end of the Issuer’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment, or, in the case such Consolidated Net Income for such period is a deficit, minus 100% of such deficit or (B) with respect to a Restricted Payment by TCEH or any Restricted Subsidiary of TCEH, 50% of the Consolidated Net Income of TCEH for the period (taken as one accounting period) beginning October 1, 2007, to the end of TCEH’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment, or, in the case such Consolidated Net Income for such period is a deficit, minus 100% of such deficit; plus

(b) 100% of the aggregate net cash proceeds and the fair market value, as determined in good faith by the Issuer, of marketable securities or other property received by the Issuer since immediately after

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the Closing Date (other than net cash proceeds to the extent such net cash proceeds have been used to incur Indebtedness, Disqualified Stock or Preferred Stock pursuant to clause (12)(a) of the second paragraph of “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”) from the issue or sale of:

(i) (A) Equity Interests of the Issuer, including Treasury Capital Stock (as defined below), but excluding cash proceeds and the fair market value, as determined in good faith by the Issuer, of marketable securities or other property received from the sale of:

(x) Equity Interests to members of management, directors or consultants of the Issuer, any direct or indirect parent company of the Issuer and the Issuer’s Subsidiaries after the Closing Date to the extent such amounts have been applied to Restricted Payments made in accordance with clause (4) of the next succeeding paragraph; and

(y) Designated Preferred Stock; and

(B) to the extent such net cash proceeds are actually contributed to the capital of the Issuer, Equity Interests of the Issuer’s direct or indirect parent companies (excluding contributions of the proceeds from the sale of Designated Preferred Stock of such companies or contributions to the extent such amounts have been applied to Restricted Payments made in accordance with clause (4) of the next succeeding paragraph); or

(ii) debt securities of the Issuer that have been converted into or exchanged for such Equity Interests of the Issuer;

provided, however, that this clause (b) shall not include the proceeds from (V) Refunding Capital Stock (as defined below), (W) Equity Interests or debt securities of the Issuer sold to a Restricted Subsidiary, as the case may be, (X) Disqualified Stock or debt securities that have been converted into or exchanged for Disqualified Stock or (Y) Excluded Contributions; plus

(c) 100% of the aggregate amount of cash and the fair market value, as determined in good faith by the Issuer, of marketable securities or other property contributed to the capital of the Issuer following the Closing Date (other than net cash proceeds to the extent such net cash proceeds (i) have been used to incur Indebtedness, Disqualified Stock or Preferred Stock pursuant to clause (12)(a) of the second paragraph of “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock,” (ii) are contributed by a Restricted Subsidiary or (iii) constitute Excluded Contributions); plus

(d) 100% of the aggregate amount received in cash and the fair market value, as determined in good faith by the Issuer, of marketable securities or other property received by means of:

(i) the sale or other disposition (other than to the Issuer or a Restricted Subsidiary) of Restricted Investments made by the Issuer or its Restricted Subsidiaries after the Closing Date and repurchases and redemptions of such Restricted Investments from the Issuer or its Restricted Subsidiaries and repayments of loans or advances, and releases of guarantees, which constitute Restricted Investments by the Issuer or its Restricted Subsidiaries after the Closing Date; or

(ii) the sale (other than to the Issuer or a Restricted Subsidiary) of the stock of an Unrestricted Subsidiary (other than (x) to the extent the Investment in such Unrestricted Subsidiary was made by the Issuer or a Restricted Subsidiary pursuant to clause (7) of the next succeeding paragraph (y) to the extent such Investment constituted a Permitted Investment or (z) an Investment in the Oncor Subsidiaries) or a distribution or dividend from an Unrestricted Subsidiary (other than distributions or dividends from the Oncor Subsidiaries except to the extent such distributions or dividends exceed the aggregate amount of Investments in the Oncor Subsidiaries then outstanding under clauses (7) and (11) of the next succeeding paragraph and clauses (8) and (13) of the definition of Permitted Investments; and to the extent that the amount of such distributions or dividends does not exceed such aggregate amount of Investments then

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outstanding under such clauses, the amount of such Investments then outstanding under any of such clauses shall be reduced by the amount of such distributions or dividends received) after the Closing Date; plus

(e) in the case of the redesignation of an Unrestricted Subsidiary (other than the Oncor Subsidiaries) as a Restricted Subsidiary after the Closing Date, the fair market value of the Investment in such Unrestricted Subsidiary, as determined by the Issuer in good faith (or if such fair market value exceeds $200.0 million, in writing by an Independent Financial Advisor), at the time of the redesignation of such Unrestricted Subsidiary as a Restricted Subsidiary other than to the extent the Investment in such Unrestricted Subsidiary was made by the Issuer or a Restricted Subsidiary pursuant to clause (7) of the next succeeding paragraph or to the extent such Investment constituted a Permitted Investment.

The foregoing provisions will not prohibit:

(1) the payment of any dividend within 60 days after the date of declaration thereof, if at the date of declaration such payment would have complied with the provisions of the Indenture;

(2)(a) the redemption, repurchase, retirement or other acquisition of any Equity Interests (“Treasury Capital Stock”) or Subordinated Indebtedness of the Issuer or a Guarantor or any Equity Interests of any direct or indirect parent company of the Issuer, in exchange for, or out of the proceeds of the substantially concurrent sale (other than to a Restricted Subsidiary) of, Equity Interests of the Issuer or any direct or indirect parent company of the Issuer to the extent contributed to the capital of the Issuer (in each case, other than any Disqualified Stock) (“Refunding Capital Stock”) and (b) if immediately prior to the retirement of Treasury Capital Stock, the declaration and payment of dividends thereon was permitted under clause (6) of this paragraph, the declaration and payment of dividends on the Refunding Capital Stock (other than Refunding Capital Stock the proceeds of which were used to redeem, repurchase, retire or otherwise acquire any Equity Interests of any direct or indirect parent company of the Issuer) in an aggregate amount per year no greater than the aggregate amount of dividends per annum that were declarable and payable on such Treasury Capital Stock immediately prior to such retirement;

(3) the redemption, repurchase or other acquisition or retirement of Subordinated Indebtedness of the Issuer or a Guarantor made in exchange for, or out of the proceeds of the substantially concurrent sale of, new Indebtedness of the Issuer or a Guarantor, as the case may be, which is incurred in compliance with the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” so long as:

(a) the principal amount (or accreted value) of such new Indebtedness does not exceed the principal amount of (or accreted value, if applicable), plus any accrued and unpaid interest on, the Subordinated Indebtedness being so redeemed, repurchased, acquired or retired for value, plus the amount of any reasonable premium (including reasonable tender premiums), defeasance costs and any reasonable fees and expenses incurred in connection with the issuance of such new Indebtedness;

(b) such new Indebtedness is subordinated to the Notes or the applicable Guarantee at least to the same extent as such Subordinated Indebtedness so purchased, exchanged, redeemed, repurchased, acquired or retired for value;

(c) such new Indebtedness has a final scheduled maturity date equal to or later than the final scheduled maturity date of the Subordinated Indebtedness being so redeemed, repurchased, acquired or retired; and

(d) such new Indebtedness has a Weighted Average Life to Maturity equal to or greater than the remaining Weighted Average Life to Maturity of the Subordinated Indebtedness being so redeemed, repurchased, acquired or retired;

(4) a Restricted Payment to pay for the repurchase, retirement or other acquisition or retirement for value of Equity Interests (other than Disqualified Stock) of the Issuer or any of its direct or indirect parent

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companies held by any future, present or former employee, director or consultant of the Issuer, any of its Subsidiaries or any of its direct or indirect parent companies pursuant to any management equity plan or stock option plan or any other management or employee benefit plan or agreement, including any Equity Interests rolled over by management of the Issuer or any of its direct or indirect parent companies in connection with the Transactions; provided, however, that the aggregate Restricted Payments made under this clause (4) do not exceed in any calendar year $25.0 million (which shall increase to $50.0 million subsequent to the consummation of an underwritten public Equity Offering by the Issuer or any direct or indirect parent entity of the Issuer) (with unused amounts in any calendar year being carried over to succeeding calendar years subject to a maximum (without giving effect to the following proviso) of $75.0 million in any calendar year (which shall increase to $150.0 million subsequent to the consummation of an underwritten public Equity Offering by the Issuer or any direct or indirect parent corporation of the Issuer)); provided, further, that such amount in any calendar year may be increased by an amount not to exceed:

(a) the cash proceeds from the sale of Equity Interests (other than Disqualified Stock) of the Issuer and, to the extent contributed to the Issuer, Equity Interests of any of the Issuer’s direct or indirect parent companies, in each case to members of management, directors or consultants of the Issuer, any of its Subsidiaries or any of its direct or indirect parent companies that occurs after the Closing Date, to the extent the cash proceeds from the sale of such Equity Interests have not otherwise been applied to the payment of Restricted Payments by virtue of clause (3) of the preceding paragraph; plus

(b) the cash proceeds of key man life insurance policies received by the Issuer or its Restricted Subsidiaries after the Closing Date; less

(c) the amount of any Restricted Payments previously made with the cash proceeds described in clauses (a) and (b) of this clause (4);

and provided, further, that cancellation of Indebtedness owing to the Issuer or any Restricted Subsidiary from members of management of the Issuer, any of the Issuer’s direct or indirect parent companies or any of the Issuer’s Restricted Subsidiaries in connection with a repurchase of Equity Interests of the Issuer or any of its direct or indirect parent companies will not be deemed to constitute a Restricted Payment for purposes of this covenant or any other provision of the Indenture;

(5) the declaration and payment of dividends to holders of any class or series of Disqualified Stock of the Issuer or any of its Restricted Subsidiaries or any class or series of Preferred Stock of any Restricted Subsidiary issued in accordance with the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” to the extent such dividends are included in the definition of “Fixed Charges”;

(6)(a) the declaration and payment of dividends to holders of any class or series of Designated Preferred Stock (other than Disqualified Stock) issued by the Issuer after the Closing Date;

(b) the declaration and payment of dividends to a direct or indirect parent company of the Issuer, the proceeds of which will be used to fund the payment of dividends to holders of any class or series of Designated Preferred Stock (other than Disqualified Stock) of such parent corporation issued after the Closing Date; provided that the amount of dividends paid pursuant to this clause (b) shall not exceed the aggregate amount of cash actually contributed to the Issuer from the sale of such Designated Preferred Stock; or

(c) the declaration and payment of dividends on Refunding Capital Stock that is Preferred Stock in excess of the dividends declarable and payable thereon pursuant to clause (2) of this paragraph;

provided, however, in the case of each of (a) and (c) of this clause (6), that for the most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date of issuance of such Designated Preferred Stock or the declaration of such dividends on Refunding Capital Stock that is Preferred Stock, after giving effect to such issuance or declaration on a pro forma basis, the Restricted Payment Coverage Ratio for the most recently ended four fiscal quarters for which internal financial statements are available immediately preceding the date of such Restricted Payment would have been at least 2.00 to 1.00;

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(7) Investments in Unrestricted Subsidiaries having an aggregate fair market value (with the fair market value of each Investment being measured at the time made and without giving effect to subsequent changes in value), taken together with all other Investments made pursuant to this clause (7) that are at the time outstanding, without giving effect to the sale of an Unrestricted Subsidiary to the extent the proceeds of such sale do not consist of cash or marketable securities, not to exceed (A) 1.5% of Total Assets at the time of such Investment and (B) to the extent invested in any of the Oncor Subsidiaries, $500.0 million;

(8) repurchases of Equity Interests deemed to occur upon exercise of stock options or warrants if such Equity Interests represent a portion of the exercise price of such options or warrants;

(9) the declaration and payment of dividends on the Issuer’s common stock (or the payment of dividends to any direct or indirect parent entity to fund a payment of dividends on such entity’s common stock), following consummation of the first public offering of the Issuer’s common stock or the common stock of any of its direct or indirect parent companies after the Closing Date, of up to 6% per annum of the net cash proceeds received by or contributed to the Issuer in or from any such public offering, other than public offerings with respect to the Issuer’s common stock registered on Form S-4 or Form S-8 and other than any public sale constituting an Excluded Contribution;

(10) Restricted Payments that are made with Excluded Contributions;

(11) other Restricted Payments in an aggregate amount taken together with all other Restricted Payments made pursuant to this clause (11) not to exceed 2.0% of Total Assets at the time made;

(12) distributions or payments of Receivables Fees;

(13) any Restricted Payment made as part of or in connection with the Transactions (including payments made after the Closing Date in respect of the Issuer’s and its Subsidiaries’ long-term incentive plan or in respect of tax gross-ups or other deferred compensation) and the fees and expenses related thereto or used to fund amounts owed to Affiliates (including dividends to any direct or indirect parent of the Issuer to permit payment by such parent of such amount), in each case to the extent permitted by the covenant described under “—Transactions with Affiliates”;

(14) the repurchase, redemption or other acquisition or retirement for value of any Subordinated Indebtedness in accordance with the provisions similar to those described under the captions “—Repurchase at the Option of Holders—Change of Control” and “—Repurchase at the Option of Holders—Asset Sales”; provided that all Notes tendered by Holders in connection with a Change of Control Offer or Asset Sale Offer, as applicable, have been repurchased, redeemed or acquired for value; or

(15) the declaration and payment of dividends by the Issuer to, or the making of loans to, any direct or indirect parent in amounts required for any direct or indirect parent companies to pay, in each case without duplication,

(a) franchise and excise taxes and other fees, taxes and expenses required to maintain their corporate existence;

(b) foreign, federal, state and local income taxes, to the extent such income taxes are attributable to the income of the Issuer and its Restricted Subsidiaries and, to the extent of the amount actually received from its Unrestricted Subsidiaries, in amounts required to pay such taxes to the extent attributable to the income of such Unrestricted Subsidiaries; provided that in each case the amount of such payments in any fiscal year does not exceed the amount that the Issuer and its Subsidiaries would be required to pay in respect of foreign, federal, state and local taxes for such fiscal year were the Issuer, its Restricted Subsidiaries and its Unrestricted Subsidiaries (to the extent described above) to pay such taxes separately from any such parent entity;

(c) customary salary, bonus and other benefits payable to officers and employees of any direct or indirect parent company of the Issuer to the extent such salaries, bonuses and other benefits are attributable to the ownership or operation of the Issuer and its Restricted Subsidiaries;

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(d) general corporate operating and overhead costs and expenses of any direct or indirect parent company of the Issuer to the extent such costs and expenses are attributable to the ownership or operation of the Issuer and its Restricted Subsidiaries;

(e) fees and expenses other than to Affiliates of the Issuer related to any unsuccessful equity or debt offering of such parent entity;

provided, however, that at the time of, and after giving effect to, any Restricted Payment permitted under clauses (7) and (11), no Default shall have occurred and be continuing or would occur as a consequence thereof.

All of the Issuer’s Subsidiaries (other than the Oncor Subsidiaries) are Restricted Subsidiaries. The Issuer will not permit any Unrestricted Subsidiary to become a Restricted Subsidiary except pursuant to the last sentence of the definition of “Unrestricted Subsidiary.” For purposes of designating any Restricted Subsidiary as an Unrestricted Subsidiary, all outstanding Investments by the Issuer and its Restricted Subsidiaries (except to the extent repaid) in the Subsidiary so designated will be deemed to be Restricted Payments in an amount determined as set forth in the last sentence of the definition of “Investments.” Such designation will be permitted only if a Restricted Payment in such amount would be permitted at such time, whether pursuant to the first paragraph of this covenant or under clause (7), (10) or (11) of the second paragraph of this covenant, or pursuant to the definition of “Permitted Investments,” and if such Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. Unrestricted Subsidiaries are not subject to any of the restrictive covenants set forth in the Indenture.

Notwithstanding the foregoing provisions of this covenant, the Issuer will not, and will not permit any of its Restricted Subsidiaries to, pay any cash dividend or make any cash distribution on, or in respect of, the Issuer’s Capital Stock or purchase for cash or otherwise acquire for cash any Capital Stock of the Issuer or any direct or indirect parent of the Issuer for the purpose of paying any cash dividend or making any cash distribution to, or acquiring Capital Stock of any direct or indirect parent of the Issuer for cash from, the Investors, or guarantee any Indebtedness of any Affiliate of the Issuer for the purpose of paying such dividend, making such distribution or so acquiring such Capital Stock to or from the Investors, in each case by means of utilization of the cumulative Restricted Payment credit provided by the first paragraph of this covenant, or the exceptions provided by clauses (1), (7) or (11) of the second paragraph of this covenant or clauses (8), (10) or (13) of the definition of “Permitted Investments,” unless (x) at the time and after giving effect to such payment, the Consolidated Leverage Ratio of the Issuer would be equal to or less than 7.00 to 1.00 and (y) such payment is otherwise in compliance with this covenant.

Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock

The Issuer will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise (collectively, “incur” and collectively, an “incurrence”) with respect to any Indebtedness (including Acquired Indebtedness), and the Issuer will not issue any shares of Disqualified Stock and will not permit any Restricted Subsidiary to issue any shares of Disqualified Stock or Preferred Stock; provided, however, that (i) the Issuer may incur Indebtedness (including Acquired Indebtedness) or issue shares of Disqualified Stock, and any of its Restricted Subsidiaries (other than TCEH and its Restricted Subsidiaries) may incur Indebtedness (including Acquired Indebtedness), issue shares of Disqualified Stock and issue shares of Preferred Stock, if the Fixed Charge Coverage Ratio on a consolidated basis for the Issuer and its Restricted Subsidiaries’ most recently ended four fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or Preferred Stock is issued would have been at least 2.00 to 1.00 and (ii) TCEH or any of its Restricted Subsidiaries may Incur Indebtedness (including Acquired Indebtedness), issue shares of Disqualified Stock and issue shares of Disqualified Stock and issue shares of Preferred Stock, if the Fixed Charge Coverage Ratio on a consolidated basis for TCEH and its Restricted Subsidiaries most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is Incurred or such Disqualified

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Stock or Preferred Stock is issued would have been at least 2.00 to 1.00, in each case determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred, or the Disqualified Stock or Preferred Stock had been issued, as the case may be, and the application of proceeds therefrom had occurred at the beginning of such four-quarter period.

The foregoing limitations will not apply to:

(1) the incurrence of Indebtedness under (x) Credit Facilities by the Issuer or any of its Restricted Subsidiaries and the issuance and creation of letters of credit and bankers’ acceptances thereunder (with letters of credit and bankers’ acceptances being deemed to have a principal amount equal to the face amount thereof), up to an aggregate principal amount of $26,500.0 million outstanding at any one time and (y) any Collateral Posting Facility;

(2) the incurrence (x) by the Issuer and any Guarantor of Indebtedness represented by the Notes (including any PIK Notes and Guarantees thereof) (other than any Additional Notes and any Exchange Notes (including Guarantees thereof)) and (y) by Energy Future Competitive Holdings or any of its Subsidiaries of Indebtedness represented by the TCEH Notes (including guarantees thereof);

(3) Indebtedness of the Issuer and its Restricted Subsidiaries in existence on the Closing Date (other than Indebtedness described in clauses (1) and (2)), including the Existing Notes, loans under the EFH Senior Interim Facility (including any PIK interest which may be paid with respect thereto) and loans under the TCEH Senior Interim Facility (including any PIK interest which may be paid with respect thereto);

(4) Indebtedness consisting of Capitalized Lease Obligations and Purchase Money Obligations, so long as such Indebtedness (except Environmental CapEx Debt) exists at the date of such purchase, lease or improvement, or is created within 270 days thereafter;

(5) Indebtedness incurred by the Issuer or any of its Restricted Subsidiaries constituting reimbursement obligations with respect to letters of credit issued in the ordinary course of business, including letters of credit in respect of workers’ compensation or employee health claims, or other Indebtedness with respect to reimbursement-type obligations regarding workers’ compensation or employee health claims; provided, however, that upon the drawing of such letters of credit or the incurrence of such Indebtedness, such obligations are reimbursed within 30 days following such drawing or incurrence;

(6) Indebtedness arising from agreements of the Issuer or its Restricted Subsidiaries providing for indemnification, adjustment of purchase price or similar obligations, in each case, incurred or assumed in connection with the disposition of any business, assets or a Subsidiary, other than guarantees of Indebtedness incurred by any Person acquiring all or any portion of such business, assets or a Subsidiary for the purpose of financing such acquisition; provided, however, that such Indebtedness is not reflected on the balance sheet of the Issuer, or any of its Restricted Subsidiaries (contingent obligations referred to in a footnote to financial statements and not otherwise reflected on the balance sheet will not be deemed to be reflected on such balance sheet for purposes of this clause (6));

(7) Indebtedness of the Issuer to a Restricted Subsidiary; provided that any such Indebtedness (other than intercompany loans from TCEH and its Subsidiaries required to be unsubordinated by the terms of any Indebtedness of TCEH or such Subsidiaries) owing to a Restricted Subsidiary that is not a Guarantor is expressly subordinated in right of payment to the Notes; provided, further, that any subsequent issuance or transfer of any Capital Stock or any other event which results in any Restricted Subsidiary ceasing to be a Restricted Subsidiary or any other subsequent transfer of any such Indebtedness (except to the Issuer or another Restricted Subsidiary) shall be deemed, in each case, to be an incurrence of such Indebtedness not permitted by this clause (7);

(8) Indebtedness of a Restricted Subsidiary to the Issuer or another Restricted Subsidiary; provided that if a Guarantor incurs such Indebtedness to a Restricted Subsidiary that is not a Guarantor (other than intercompany loans from TCEH and its Subsidiaries required to be unsubordinated by the terms of any Indebtedness of TCEH or such Subsidiaries), such Indebtedness is expressly subordinated in right of

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payment to the Guarantee of the Notes of such Guarantor; provided, further, that any subsequent issuance or transfer of any Capital Stock or any other event which results in any Restricted Subsidiary ceasing to be a Restricted Subsidiary or any other subsequent transfer of any such Indebtedness (except to the Issuer or another Restricted Subsidiary) shall be deemed, in each case, to be an incurrence of such Indebtedness not permitted by this clause (8);

(9) shares of Preferred Stock of a Restricted Subsidiary issued to the Issuer or another Restricted Subsidiary; provided that any subsequent issuance or transfer of any Capital Stock or any other event which results in any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any other subsequent transfer of any such shares of Preferred Stock (except to the Issuer or another of its Restricted Subsidiaries) shall be deemed in each case to be an issuance of such shares of Preferred Stock not permitted by this clause (9);

(10) Hedging Obligations; provided that (i) other than in the case of commodity Hedging Obligations, such Hedging Obligations are not entered into for speculative purposes (as determined by the Issuer in its reasonable discretion acting in good faith) and (ii) in the case of speculative commodity Hedging Obligations, such Hedging Obligations are entered into in the ordinary course of business and are consistent with past practice;

(11) obligations in respect of performance, bid, appeal and surety bonds and completion guarantees provided by the Issuer or any of its Restricted Subsidiaries in the ordinary course of business;

(12)(a) Indebtedness or Disqualified Stock of the Issuer and Indebtedness, Disqualified Stock or Preferred Stock of the Issuer or any Restricted Subsidiary equal to 100.0% of the net cash proceeds received by the Issuer since immediately after the Closing Date from the issue or sale of Equity Interests of the Issuer or cash contributed to the capital of the Issuer (in each case, other than Excluded Contributions or proceeds of Disqualified Stock or sales of Equity Interests to the Issuer or any of its Subsidiaries) as determined in accordance with clauses (3)(b) and (3)(c) of the first paragraph of “—Limitation on Restricted Payments” to the extent such net cash proceeds or cash have not been applied pursuant to such clauses to make Restricted Payments or to make other Investments, payments or exchanges pursuant to the second paragraph of “—Limitation on Restricted Payments” or to make Permitted Investments (other than Permitted Investments specified in clauses (1) and (3) of the definition thereof) and (b) Indebtedness or Disqualified Stock of the Issuer and Indebtedness, Disqualified Stock or Preferred Stock of the Issuer or any Restricted Subsidiary not otherwise permitted hereunder in an aggregate principal amount or liquidation preference, which when aggregated with the principal amount and liquidation preference of all other Indebtedness, Disqualified Stock and Preferred Stock then outstanding and incurred pursuant to this clause (12)(b), does not at any one time outstanding exceed $1,750.0 million (it being understood that any Indebtedness, Disqualified Stock or Preferred Stock incurred pursuant to this clause (12)(b) shall cease to be deemed incurred or outstanding for purposes of this clause (12)(b) but shall be deemed incurred for the purposes of the first paragraph of this covenant from and after the first date on which the Issuer or such Restricted Subsidiary could have incurred such Indebtedness, Disqualified Stock or Preferred Stock under the first paragraph of this covenant without reliance on this clause (12)(b));

(13) the incurrence or issuance by the Issuer or any Restricted Subsidiary of Indebtedness, Disqualified Stock or Preferred Stock which serves to refund or refinance any Indebtedness, Disqualified Stock or Preferred Stock of the Issuer or any Restricted Subsidiary incurred as permitted under the first paragraph of this covenant and clauses (2), (3), (4) and (12)(a) above, this clause (13) and clause (14) below or any Indebtedness, Disqualified Stock or Preferred Stock of the Issuer or any Restricted Subsidiary issued to so refund or refinance such Indebtedness, Disqualified Stock or Preferred Stock of the Issuer or any Restricted Subsidiary including additional Indebtedness, Disqualified Stock or Preferred Stock incurred to pay premiums (including reasonable tender premiums), defeasance costs and fees in connection therewith (the “Refinancing Indebtedness”) prior to its respective maturity; provided, however, that such Refinancing Indebtedness:

(a) has a Weighted Average Life to Maturity at the time such Refinancing Indebtedness is incurred which is not less than the remaining Weighted Average Life to Maturity of the Indebtedness, Disqualified Stock or Preferred Stock being refunded or refinanced,

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(b) to the extent such Refinancing Indebtedness refinances (i) Indebtedness subordinated or pari passu to the Notes or any Guarantee thereof, such Refinancing Indebtedness is subordinated or pari passu to the Notes or the Guarantee at least to the same extent as the Indebtedness being refinanced or refunded or (ii) Disqualified Stock or Preferred Stock, such Refinancing Indebtedness must be Disqualified Stock or Preferred Stock, respectively, and

(c) shall not include Indebtedness, Disqualified Stock or Preferred Stock of a Subsidiary of the Issuer that is not a Guarantor that refinances Indebtedness, Disqualified Stock or Preferred Stock of the Issuer or a Guarantor;

and, provided, further, that subclause (a) of this clause (13) will not apply to any refunding or refinancing of any Obligations under Credit Facilities secured by Permitted Liens or the TCEH Senior Interim Facility; and, provided, further that with respect to any pollution control revenue bonds or similar instruments, the maturity of any series thereof shall be deemed to be the date set forth in any instrument governing such Indebtedness for the remarketing of such Indebtedness;

(14) Indebtedness, Disqualified Stock or Preferred Stock of (x) the Issuer or a Restricted Subsidiary incurred to finance an acquisition or (y) Persons that are acquired by the Issuer or any Restricted Subsidiary or merged into the Issuer or a Restricted Subsidiary in accordance with the terms of the Indenture; provided that after giving effect to such acquisition or merger, either

(A) in the case of an acquisition by or merger with the Issuer or any of its Restricted Subsidiaries other than TCEH and its Restricted Subsidiaries, either (a) the Issuer would be permitted to incur at least $1.00 of additional Indebtedness pursuant to clause (i) of the Fixed Charge Coverage Ratio test set forth in the first sentence of this covenant, or (b) such Fixed Charge Coverage Ratio of the Issuer and the Restricted Subsidiaries is greater than immediately prior to such acquisition or merger; or

(B) in the case of an acquisition by or merger with TCEH or any of its Restricted Subsidiaries, either (a) TCEH would be permitted to Incur at least $1.00 of additional Indebtedness pursuant to clause (ii) of the Fixed Charge Coverage Ratio test set forth in the first sentence of this covenant, or (b) such Fixed Charge Coverage Ratio of TCEH and its Restricted Subsidiaries is greater than immediately prior to such acquisition or merger;

(15) Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business; provided that such Indebtedness is extinguished within two Business Days of its incurrence;

(16) Indebtedness of the Issuer or any of its Restricted Subsidiaries supported by a letter of credit issued pursuant to any Credit Facilities, in a principal amount not in excess of the stated amount of such letter of credit;

(17)(a) any guarantee by the Issuer or a Restricted Subsidiary of Indebtedness or other obligations of any Restricted Subsidiary, so long as the incurrence of such Indebtedness incurred by such Restricted Subsidiary is permitted under the terms of the Indenture, or (b) any guarantee by a Restricted Subsidiary of Indebtedness of the Issuer; provided that such guarantee is incurred in accordance with the covenant described under “—Limitation on Guarantees of Indebtedness by Restricted Subsidiaries”;

(18) Indebtedness of the Issuer or any of its Restricted Subsidiaries consisting of (i) the financing of insurance premiums or (ii) take-or-pay obligations contained in supply arrangements, in each case, incurred in the ordinary course of business; and

(19) Indebtedness consisting of Indebtedness issued by the Issuer or any of its Restricted Subsidiaries to current or former officers, directors and employees thereof, their respective estates, spouses or former spouses, in each case to finance the purchase or redemption of Equity Interests of the Issuer or any direct or indirect parent company of the Issuer to the extent described in clause (4) of the second paragraph under the caption “—Limitation on Restricted Payments.”

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For purposes of determining compliance with this covenant:

(1) in the event that an item of Indebtedness, Disqualified Stock or Preferred Stock (or any portion thereof) meets the criteria of more than one of the categories of permitted Indebtedness, Disqualified Stock or Preferred Stock described in clauses (1) through (19) above or is entitled to be incurred pursuant to the first paragraph of this covenant, the Issuer, in its sole discretion, will classify or reclassify such item of Indebtedness, Disqualified Stock or Preferred Stock (or any portion thereof) and will only be required to include the amount and type of such Indebtedness, Disqualified Stock or Preferred Stock in one of the above clauses; and

(2) at the time of incurrence, the Issuer will be entitled to divide and classify an item of Indebtedness in more than one of the types of Indebtedness described in the first and second paragraphs above;

provided that all Indebtedness outstanding under the TCEH Senior Secured Facilities on the Closing Date will be treated as incurred on the Closing Date under clause (1) of the preceding paragraph.

Accrual of interest, the accretion of accreted value and the payment of interest in the form of additional Indebtedness, Disqualified Stock or Preferred Stock will not be deemed to be an incurrence of Indebtedness, Disqualified Stock or Preferred Stock for purposes of this covenant.

For purposes of determining compliance with any U.S. dollar-denominated restriction on the incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was incurred, in the case of term debt, or first committed, in the case of revolving credit debt; provided that if such Indebtedness is incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced.

The principal amount of any Indebtedness incurred to refinance other Indebtedness, if incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such respective Indebtedness is denominated that is in effect on the date of such refinancing.

The Indenture provides that the Issuer will not, and will not permit any Guarantor to, directly or indirectly, incur any Indebtedness (including Acquired Indebtedness) that is subordinated or junior in right of payment to any Indebtedness of the Issuer or such Guarantor, as the case may be, unless such Indebtedness is expressly subordinated in right of payment to the Notes or such Guarantor’s Guarantee to the extent and in the same manner as such Indebtedness is subordinated to other Indebtedness of the Issuer or such Guarantor, as the case may be.

The Indenture does not treat (1) unsecured Indebtedness as subordinated or junior to Secured Indebtedness merely because it is unsecured or (2) Senior Indebtedness as subordinated or junior to any other Senior Indebtedness merely because it has a junior priority with respect to the same collateral.

Liens

The Issuer will not, and will not permit any Guarantor to, directly or indirectly, create, incur, assume or suffer to exist any Lien (except Permitted Liens) that secures obligations under any Indebtedness or any related guarantee, on any asset or property of the Issuer or any Guarantor, or any income or profits therefrom, or assign or convey any right to receive income therefrom, unless:

(1) in the case of Liens securing Subordinated Indebtedness, the Notes and related Guarantees are secured by a Lien on such property, assets or proceeds that is senior in priority to such Liens; or

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(2) in all other cases, the Notes or the Guarantees are equally and ratably secured or are secured by a Lien on such property, assets or proceeds that is senior in priority to such Liens;

except that the foregoing shall not apply to (a) Liens securing the Notes and the related Guarantees, (b) Liens securing Indebtedness permitted to be incurred under Credit Facilities, including any letter of credit relating thereto, that was permitted by the terms of the Indenture to be incurred pursuant to clause (1) of the second paragraph under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and (c) Liens incurred to secure Obligations in respect of any Indebtedness permitted to be incurred pursuant to the covenant described above under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”; provided that, with respect to Liens securing Obligations permitted under this subclause (c), at the time of incurrence and after giving pro forma effect thereto, the Consolidated Secured Debt Ratio for the most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such event for which such calculation is being made shall occur would be no greater than 5.0 to 1.0. Any Lien which is granted to secure the Notes under this covenant shall be discharged at the same time as the discharge of the Lien (other than through the exercise of remedies with respect thereto) that gave rise to the obligations to secure to the Notes.

Merger, Consolidation or Sale of All or Substantially All Assets

The Issuer may not consolidate or merge with or into or wind up into (whether or not the Issuer is the surviving corporation), or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets, in one or more related transactions, to any Person unless:

(1) the Issuer is the surviving corporation or the Person formed by or surviving any such consolidation or merger (if other than the Issuer) or to which such sale, assignment, transfer, lease, conveyance or other disposition will have been made is a corporation organized or existing under the laws of the jurisdiction of organization of the Issuer or the laws of the United States, any state thereof, the District of Columbia, or any territory thereof (such Person, as the case may be, being herein called the “Successor Company”);

(2) the Successor Company, if other than the Issuer, expressly assumes (i) all the obligations of the Issuer under the Notes and the Indenture pursuant to supplemental indentures or other documents or instruments in form reasonably satisfactory to the Trustee and (ii) the Registration Rights Agreement;

(3) immediately after such transaction, no Default exists;

(4) immediately after giving pro forma effect to such transaction and any related financing transactions, as if such transactions had occurred at the beginning of the applicable four-quarter period,

(a) the Successor Company would be permitted to incur at least $1.00 of additional Indebtedness pursuant to clause (i) of the Fixed Charge Coverage Ratio test set forth in the first sentence of the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock,” or

(b) such Fixed Charge Coverage Ratio for the Successor Company and its Restricted Subsidiaries would be greater than such ratio for the Issuer and its Restricted Subsidiaries immediately prior to such transaction;

(5) each Guarantor, unless it is the other party to the transactions described above, in which case clause (b) of the second succeeding paragraph shall apply, shall have by supplemental indenture confirmed that its Guarantee shall apply to such Person’s obligations under the Indenture, the Notes and the Registration Rights Agreement; and

(6) the Issuer shall have delivered to the Trustee an Officer’s Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indentures, if any, comply with the Indenture and, if a supplemental indenture is required in connection with such transaction, such supplement shall comply with the applicable provisions of the Indenture.

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The Successor Company will succeed to, and be substituted for the Issuer, as the case may be, under the Indenture, the Guarantees and the Notes, as applicable. Notwithstanding the foregoing clauses (3) and (4),

(1) any Restricted Subsidiary may consolidate with or merge into or transfer all or part of its properties and assets to the Issuer, and

(2) the Issuer may merge with an Affiliate of the Issuer, as the case may be, solely for the purpose of reincorporating the Issuer in a State of the United States, the District of Columbia or any territory thereof so long as the amount of Indebtedness of the Issuer and its Restricted Subsidiaries is not increased thereby.

Subject to certain limitations described in the Indenture governing release of a Guarantee upon the sale, disposition or transfer of a Guarantor, no Guarantor will, and the Issuer will not permit any Guarantor to, consolidate or merge with or into or wind up into (whether or not the Issuer or Guarantor is the surviving corporation), or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets, in one or more related transactions, to any Person unless:

(1)(a) such Guarantor is the surviving corporation or the Person formed by or surviving any such consolidation or merger (if other than such Guarantor) or to which such sale, assignment, transfer, lease, conveyance or other disposition will have been made is a corporation, partnership, limited partnership, limited liability corporation or trust organized or existing under the laws of the jurisdiction of organization of such Guarantor, as the case may be, or the laws of the United States, any state thereof, the District of Columbia, or any territory thereof (such Guarantor or such Person, as the case may be, being herein called the “Successor Person”);

(b) the Successor Person, if other than such Guarantor, expressly assumes all the obligations of such Guarantor under the Indenture and such Guarantor’s related Guarantee pursuant to supplemental indentures or other documents or instruments in form reasonably satisfactory to the Trustee;

(c) immediately after such transaction, no Default exists; and

(d) the Issuer shall have delivered to the Trustee an Officer’s Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indentures, if any, comply with the Indenture; or

(2) the transaction is made in compliance with the covenant described under “Repurchase at the Option of Holders—Asset Sales.”

Subject to certain limitations described in the Indenture, the Successor Person will succeed to, and be substituted for, such Guarantor under the Indenture and such Guarantor’s Guarantee. Notwithstanding the foregoing, any Guarantor may (i) merge into or transfer all or part of its properties and assets to another Guarantor or the Issuer, (ii) merge with an Affiliate of the Issuer solely for the purpose of reincorporating the Guarantor in the United States, any state thereof, the District of Columbia or any territory thereof or (iii) convert into a corporation, partnership, limited partnership, limited liability corporation or trust organized or existing under the laws of the jurisdiction of organization of such Guarantor.

Transactions with Affiliates

The Issuer will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of the Issuer (each of the foregoing, an “Affiliate Transaction”) involving aggregate payments or consideration in excess of $25.0 million, unless:

(1) such Affiliate Transaction is on terms that are not materially less favorable to the Issuer or its relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Issuer or such Restricted Subsidiary with an unrelated Person on an arm’s-length basis; and

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(2) the Issuer delivers to the Trustee with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate payments or consideration in excess of $50.0 million, a resolution adopted by the majority of the board of directors of the Issuer approving such Affiliate Transaction and set forth in an Officer’s Certificate certifying that such Affiliate Transaction complies with clause (1) above.

The foregoing provisions will not apply to the following:

(1) transactions between or among the Issuer or any of its Restricted Subsidiaries or between or among the Issuer, any of its Restricted Subsidiaries and the Oncor Subsidiaries in the ordinary course of business;

(2) Restricted Payments permitted by the provisions of the Indenture described under the covenant “—Limitation on Restricted Payments” and the definition of “Permitted Investments”;

(3) the payment of management, consulting, monitoring and advisory fees and related expenses to the Investors pursuant to the Sponsor Management Agreement (plus any unpaid management, consulting, monitoring and advisory fees and related expenses accrued in any prior year) and the termination fees pursuant to the Sponsor Management Agreement, in each case as in effect on the Closing Date, or any amendment thereto (so long as any such amendment is not disadvantageous in the good faith judgment of the board of directors of the Issuer to the Holders when taken as a whole as compared to the Sponsor Management Agreement in effect on the Closing Date);

(4) the payment of reasonable and customary fees paid to, and indemnities provided for the benefit of, officers, directors, employees or consultants of Issuer, any of its direct or indirect parent companies or any of its Restricted Subsidiaries;

(5) transactions in which the Issuer or any of its Restricted Subsidiaries, as the case may be, delivers to the Trustee a letter from an Independent Financial Advisor stating that such transaction is fair to the Issuer or such Restricted Subsidiary from a financial point of view or stating that the terms are not materially less favorable to the Issuer or its relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Issuer or such Restricted Subsidiary with an unrelated Person on an arm’s-length basis;

(6) any agreement as in effect as of the Closing Date, or any amendment thereto (so long as any such amendment is not disadvantageous to the Holders when taken as a whole as compared to the applicable agreement as in effect on the Closing Date);

(7) the existence of, or the performance by the Issuer or any of its Restricted Subsidiaries of its obligations under the terms of, any stockholders agreement (including any registration rights agreement or purchase agreement related thereto) to which it is a party as of the Closing Date and any similar agreements which it may enter into thereafter; provided, however, that the existence of, or the performance by the Issuer or any of its Restricted Subsidiaries of obligations under any future amendment to any such existing agreement or under any similar agreement entered into after the Closing Date shall only be permitted by this clause (7) to the extent that the terms of any such amendment or new agreement are not otherwise disadvantageous to the Holders when taken as a whole;

(8) the Transactions (including payments made after the Closing Date in respect of the Issuer’s and its Subsidiaries’ long-term incentive plan or in respect of tax gross-ups and other deferred compensation) and the payment of all fees and expenses related to the Transactions, in each case as disclosed in this prospectus;

(9) transactions with customers, clients, suppliers, or purchasers or sellers of goods or services, in each case in the ordinary course of business and otherwise in compliance with the terms of the Indenture which are fair to the Issuer and its Restricted Subsidiaries, in the reasonable determination of the board of directors of the Issuer or the senior management thereof, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party;

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(10) the issuance of Equity Interests (other than Disqualified Stock) of the Issuer to any Permitted Holder or to any director, officer, employee or consultant;

(11) sales of accounts receivable, or participations therein, in connection with any Receivables Facility for the benefit of the Issuer or any of its Restricted Subsidiaries;

(12) payments by the Issuer or any of its Restricted Subsidiaries to any of the Investors made for any financial advisory, financing, underwriting or placement services or in respect of other investment banking activities, including, without limitation, in connection with acquisitions or divestitures, which payments are approved by a majority of the board of directors of the Issuer in good faith;

(13) payments or loans (or cancellation of loans) to employees or consultants of the Issuer, any of its direct or indirect parent companies or any of its Restricted Subsidiaries and employment agreements, stock option plans and other similar arrangements with such employees or consultants which, in each case, are approved by the Issuer in good faith;

(14) investments by the Investors in securities of the Issuer or any of its Restricted Subsidiaries so long as (i) the investment is being offered generally to other investors on the same or more favorable terms and (ii) the investment constitutes less than 5% of the proposed or outstanding issue amount of such class of securities; and

(15) payments by the Issuer (and any direct or indirect parent thereof) and its Subsidiaries pursuant to tax sharing agreements among the Issuer (and any such parent) and its Subsidiaries on customary terms to the extent attributable to the ownership or operation of the Issuer and its Subsidiaries; provided that in each case the amount of such payments in any fiscal year does not exceed the amount that the Issuer, its Restricted Subsidiaries and its Unrestricted Subsidiaries (to the extent of amounts received from Unrestricted Subsidiaries) would be required to pay in respect of foreign, federal, state and local taxes for such fiscal year were the Issuer and its Subsidiaries (to the extent described above) to pay such taxes separately from any such parent entity.

Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries

The Issuer will not, and will not permit any of its Restricted Subsidiaries that are not Guarantors to, directly or indirectly, create or otherwise cause or suffer to exist or become effective any consensual encumbrance or consensual restriction on the ability of any such Restricted Subsidiary to:

(1)(a) pay dividends or make any other distributions to the Issuer or any of its Restricted Subsidiaries on its Capital Stock or with respect to any other interest or participation in, or measured by, its profits, or

(b) pay any Indebtedness owed to the Issuer or any of its Restricted Subsidiaries;

(2) make loans or advances to the Issuer or any of its Restricted Subsidiaries; or

(3) sell, lease or transfer any of its properties or assets to the Issuer or any of its Restricted Subsidiaries,

except (in each case) for such encumbrances or restrictions existing under or by reason of:

(a) contractual encumbrances or restrictions in effect on the Closing Date, including pursuant to the TCEH Senior Secured Facilities, the TCEH Senior Interim Facility, the EFH Senior Interim Facility and the related documentation and the Existing Notes Indentures and the related documentation;

(b) (i) the Indenture and the Notes and (ii) the TCEH Notes and related documentation in effect on the Issue Date;

(c) purchase money obligations for property acquired in the ordinary course of business that impose restrictions of the nature discussed in clause (3) above on the property so acquired;

(d) applicable law or any applicable rule, regulation or order;

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(e) any agreement or other instrument of a Person acquired by the Issuer or any Restricted Subsidiary in existence at the time of such acquisition (but not created in contemplation thereof), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person and its Subsidiaries, or the property or assets of the Person and its Subsidiaries, so acquired;

(f) contracts for the sale of assets, including customary restrictions with respect to a Subsidiary of the Issuer pursuant to an agreement that has been entered into for the sale or disposition of all or substantially all of the Capital Stock or assets of such Subsidiary;

(g) Secured Indebtedness that limits the right of the debtor to dispose of the assets securing such Indebtedness that is otherwise permitted to be incurred pursuant to the covenants described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “—Liens”;

(h) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business;

(i)(A) other Indebtedness, Disqualified Stock or Preferred Stock of Foreign Subsidiaries permitted to be incurred subsequent to the Closing Date pursuant to the provisions of the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” or (B) other Indebtedness, Disqualified Stock or Preferred Stock of TCEH and its Restricted Subsidiaries permitted to be incurred subsequent to the Closing Date pursuant to the provisions of the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and either (i) the provisions relating to such encumbrance or restriction contained such Indebtedness are no less favorable to the Issuer, taken as a whole, as determined by the Issuer in good faith, than the provisions contained in the TCEH Senior Secured Facilities or the TCEH Senior Interim Facility, in each case, as in effect on the Closing Date or (ii) any such encumbrance or restriction does not prohibit (except upon a default thereunder) the payment of dividends or loans in an amount sufficient, as determined by the Issuer in good faith, to make scheduled payments of cash interest of the Notes when due;

(j) customary provisions in joint venture agreements and other agreements or arrangements relating solely to such joint venture;

(k) customary provisions contained in leases or licenses of intellectual property and other agreements, in each case entered into in the ordinary course of business;

(l) any encumbrances or restrictions of the type referred to in clauses (1), (2) and (3) above imposed by any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancing of the contracts, instruments or obligations referred to in clauses (a) through (k) above; provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are, in the good faith judgment of the Issuer, no more restrictive with respect to such encumbrance and other restrictions taken as a whole than those prior to such amendment, modification, restatement, renewal, increase, supplement, refunding, replacement or refinancing;

(m) restrictions created in connection with any Receivables Facility for the benefit of the Issuer or any of its Restricted Subsidiaries that, in the good faith determination of the Issuer, are necessary or advisable to effect the transactions contemplated under such Receivables Facility; and

(n) restrictions or conditions contained in any trading, netting, operating, construction, service, supply, purchase, sale, hedging or similar agreement to which the Issuer or any Restricted Subsidiary of the Issuer is a party entered into in the ordinary course of business; provided that such agreement prohibits the encumbrance solely to the property or assets of the Issuer or such Restricted Subsidiary

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that are the subject of such agreement, the payment rights arising thereunder and/or the proceeds thereof and does not extend to any other asset or property of the Issuer or such Restricted Subsidiary or the assets or property of any other Restricted Subsidiary.

Limitation on Guarantees of Indebtedness by Restricted Subsidiaries

The Issuer will not permit any of its Wholly-Owned Subsidiaries that are Restricted Subsidiaries (and non-Wholly-Owned Subsidiaries if such non-Wholly-Owned Subsidiaries guarantee other capital markets debt securities of the Issuer or any Guarantor), other than a Guarantor, a Foreign Subsidiary or a Receivables Subsidiary, to guarantee the payment of any Indebtedness of the Issuer unless:

(1) such Restricted Subsidiary within 30 days executes and delivers a supplemental indenture to the Indenture providing for a Guarantee by such Restricted Subsidiary, except that with respect to a guarantee of Indebtedness of the Issuer:

(a) if the Notes or such Guarantor’s Guarantee is subordinated in right of payment to such Indebtedness, the Guarantee under the supplemental indenture shall be subordinated to such Restricted Subsidiary’s guarantee with respect to such Indebtedness substantially to the same extent as the Notes are subordinated to such Indebtedness; and

(b) if such Indebtedness is by its express terms subordinated in right of payment to the Notes, any such guarantee by such Restricted Subsidiary with respect to such Indebtedness shall be subordinated in right of payment to such Guarantee substantially to the same extent as such Indebtedness is subordinated to the Notes; and

(2) such Restricted Subsidiary waives, and will not in any manner whatsoever claim or take the benefit or advantage of, any rights of reimbursement, indemnity or subrogation or any other rights against the Issuer or any other Restricted Subsidiary as a result of any payment by such Restricted Subsidiary under its Guarantee;

provided that this covenant shall not be applicable to any guarantee of any Restricted Subsidiary that existed at the time such Person became a Restricted Subsidiary and was not incurred in connection with, or in contemplation of, such Person becoming a Restricted Subsidiary.

Reports and Other Information

Notwithstanding that the Issuer may not be subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act or otherwise report on an annual and quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the SEC, the Indenture requires the Issuer to file with the SEC (and make available to the Trustee and Holders of the Notes (without exhibits), without cost to any Holder, within 15 days after it files them with the SEC) from and after the Issue Date,

(1) within 90 days (or any other time period then in effect under the rules and regulations of the Exchange Act with respect to the filing of a Form 10-K by a non-accelerated filer) after the end of each fiscal year, annual reports on Form 10-K, or any successor or comparable form, containing the information required to be contained therein, or required in such successor or comparable form;

(2) within 45 days after the end of each of the first three fiscal quarters of each fiscal year, reports on Form 10-Q containing all quarterly information that would be required to be contained in Form 10-Q, or any successor or comparable form;

(3) promptly from time to time after the occurrence of an event required to be therein reported, such other reports on Form 8-K, or any successor or comparable form; and

(4) any other information, documents and other reports which the Issuer would be required to file with the SEC if it were subject to Section 13 or 15(d) of the Exchange Act;

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in each case in a manner that complies in all material respects with the requirements specified in such form; provided that the Issuer shall not be so obligated to file such reports with the SEC if the SEC does not permit such filing, in which event the Issuer will make available such information to prospective purchasers of Notes, in addition to providing such information to the Trustee and the Holders of the Notes, in each case within 15 days after the time the Issuer would be required to file such information with the SEC if it were subject to Section 13 or 15(d) of the Exchange Act. In addition, to the extent not satisfied by the foregoing, the Issuer has agreed that, for so long as any Notes are outstanding, it will furnish to Holders and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

In the event that any direct or indirect parent company of the Issuer becomes a Guarantor of the Notes, the Indenture permits the Issuer to satisfy its obligations in this covenant with respect to financial information relating to the Issuer by furnishing financial information relating to such parent; provided that the same is accompanied by consolidating information that explains in reasonable detail the differences between the information relating to such parent, on the one hand, and the information relating to the Issuer and its Restricted Subsidiaries on a standalone basis, on the other hand.

Notwithstanding anything herein to the contrary, the Issuer will not be deemed to have failed to comply with any of its obligations hereunder for purposes of clause (3) under “Events of Default and Remedies” until 60 days after the date any report hereunder is due.

Events of Default and Remedies

The Indenture provides that each of the following is an “Event of Default”:

(1) default in payment when due and payable, upon redemption, acceleration or otherwise, of principal of, or premium, if any, on the Notes;

(2) default for 30 days or more in the payment when due of interest on or with respect to the Notes;

(3) failure by the Issuer or any Restricted Subsidiary for 60 days after receipt of written notice given by the Trustee or the Holders of not less than 30% in principal amount of the outstanding Notes to comply with any of its obligations, covenants or agreements (other than a default referred to in clauses (1) and (2) above) contained in the Indenture or the Notes;

(4) default under any mortgage, indenture or instrument under which there is issued or by which there is secured or evidenced any Indebtedness for money borrowed by the Issuer or any of its Restricted Subsidiaries or the payment of which is guaranteed by the Issuer or any of its Restricted Subsidiaries, other than Indebtedness owed to the Issuer or a Restricted Subsidiary, whether such Indebtedness or guarantee now exists or is created after the issuance of the Notes, if both:

(a) such default either results from the failure to pay any principal of such Indebtedness at its stated final maturity (after giving effect to any applicable grace periods) or relates to an obligation other than the obligation to pay principal of any such Indebtedness at its stated final maturity and results in the holder or holders of such Indebtedness causing such Indebtedness to become due prior to its stated maturity; and

(b) the principal amount of such Indebtedness, together with the principal amount of any other such Indebtedness in default for failure to pay principal at stated final maturity (after giving effect to any applicable grace periods), or the maturity of which has been so accelerated, aggregate $250.0 million or more at any one time outstanding;

(5) failure by the Issuer or any Significant Subsidiary (or any group of Restricted Subsidiaries that together would constitute a Significant Subsidiary) to pay final judgments aggregating in excess of $250.0

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million, which final judgments remain unpaid, undischarged and unstayed for a period of more than 60 days after such judgment becomes final, and in the event such judgment is covered by insurance, an enforcement proceeding has been commenced by any creditor upon such judgment or decree which is not promptly stayed;

(6) certain events of bankruptcy or insolvency with respect to the Issuer or any Significant Subsidiary (or any group of Restricted Subsidiaries that together would constitute a Significant Subsidiary); or

(7) the Guarantee of any Significant Subsidiary (or any group of Restricted Subsidiaries that together would constitute a Significant Subsidiary) shall for any reason cease to be in full force and effect or be declared null and void or any responsible officer of any Guarantor that is a Significant Subsidiary (or any group of Restricted Subsidiaries that together would constitute a Significant Subsidiary), as the case may be, denies that it has any further liability under its Guarantee or gives notice to such effect, other than by reason of the termination of the Indenture or the release of any such Guarantee in accordance with the Indenture.

If any Event of Default (other than of a type specified in clause (6) above) occurs and is continuing under the Indenture, the Trustee or the Holders of at least 30% in principal amount of the outstanding Notes may declare the principal, premium, if any, interest and any other monetary obligations on all the then outstanding Notes to be due and payable immediately.

Upon the effectiveness of such declaration, such principal and interest will be due and payable immediately. Notwithstanding the foregoing, in the case of an Event of Default arising under clause (6) of the first paragraph of this section, all outstanding Notes will become due and payable without further action or notice. The Indenture provides that the Trustee may withhold from the Holders notice of any continuing Default, except a Default relating to the payment of principal, premium, if any, or interest, if it determines that withholding notice is in their interest. In addition, the Trustee shall have no obligation to accelerate the Notes if in the best judgment of the Trustee acceleration is not in the best interest of the Holders of the Notes.

The Indenture provides that the Holders of a majority in aggregate principal amount of the outstanding Notes by notice to the Trustee may on behalf of the Holders of all of the Notes waive any existing Default and its consequences under the Indenture except a continuing Default in the payment of interest on, premium, if any, or the principal of any Note held by a non-consenting Holder. In the event of any Event of Default specified in clause (4) above, such Event of Default and all consequences thereof (excluding any resulting payment default, other than as a result of acceleration of the Notes) shall be annulled, waived and rescinded, automatically and without any action by the Trustee or the Holders, if within 20 days after such Event of Default arose:

(1) the Indebtedness or guarantee that is the basis for such Event of Default has been discharged; or

(2) holders thereof have rescinded or waived the acceleration, notice or action (as the case may be) giving rise to such Event of Default; or

(3) the default that is the basis for such Event of Default has been cured.

Subject to the provisions of the Indenture relating to the duties of the Trustee thereunder, in case an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the Indenture at the request or direction of any of the Holders of the Notes unless the Holders have offered to the Trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest when due, no Holder of a Note may pursue any remedy with respect to the Indenture or the Notes unless:

(1) such Holder has previously given the Trustee notice that an Event of Default is continuing;

(2) Holders of at least 30% in principal amount of the outstanding Notes have requested the Trustee to pursue the remedy;

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(3) Holders of the Notes have offered the Trustee reasonable security or indemnity against any loss, liability or expense;

(4) the Trustee has not complied with such request within 60 days after the receipt thereof and the offer of security or indemnity; and

(5) Holders of a majority in principal amount of the outstanding Notes have not given the Trustee a direction inconsistent with such request within such 60-day period.

Subject to certain restrictions, under the Indenture the Holders of a majority in principal amount of the outstanding Notes are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. The Trustee, however, may refuse to follow any direction that conflicts with law or the Indenture or that the Trustee determines is unduly prejudicial to the rights of any other Holder of a Note or that would involve the Trustee in personal liability.

The Indenture provides that the Issuer is required to deliver to the Trustee annually a statement regarding compliance with the Indenture, and the Issuer is required, within five Business Days, upon becoming aware of any Default, to deliver to the Trustee a statement specifying such Default.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator or stockholder of the Issuer or any Guarantor or any of their parent companies (other than the Issuer and the Guarantors) shall have any liability for any obligations of the Issuer or the Guarantors under the Notes, the Guarantees or the Indenture or for any claim based on, in respect of, or by reason of such obligations or their creation. Each Holder by accepting the Notes waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws, and it is the view of the SEC that such a waiver is against public policy.

Legal Defeasance and Covenant Defeasance

The obligations of the Issuer and the Guarantors under the Indenture will terminate (other than certain obligations) and will be released upon payment in full of all of the Notes. The Issuer may, at its option and at any time, elect to have all of its obligations discharged with respect to the Notes and have the Issuer’s and each Guarantor’s obligation discharged with respect to its Guarantee (“Legal Defeasance”) and cure all then existing Events of Default except for:

(1) the rights of Holders of Notes to receive payments in respect of the principal of, premium, if any, and interest on the Notes when such payments are due solely out of the trust created pursuant to the Indenture;

(2) the Issuer’s obligations with respect to Notes concerning issuing temporary notes, registration of such Notes, mutilated, destroyed, lost or stolen Notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3) the rights, powers, trusts, duties and immunities of the Trustee, and the Issuer’s obligations in connection therewith; and

(4) the Legal Defeasance provisions of the Indenture.

In addition, the Issuer may, at its option and at any time, elect to have its obligations and those of each Guarantor released with respect to certain covenants that are described in the Indenture (“Covenant Defeasance”) and thereafter any omission to comply with such obligations shall not constitute a Default with respect to the Notes. In the event Covenant Defeasance occurs, certain events (not including bankruptcy, receivership,

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rehabilitation and insolvency events pertaining to the Issuer) described under “Events of Default and Remedies” will no longer constitute an Event of Default with respect to the Notes.

In order to exercise either Legal Defeasance or Covenant Defeasance with respect to the Notes:

(1) the Issuer must irrevocably deposit with the Trustee, in trust, for the benefit of the Holders of the Notes, cash in U.S. dollars, Government Securities, or a combination thereof, in such amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, premium, if any, and interest due on the Notes on the stated maturity date or on the redemption date, as the case may be, of such principal, premium, if any, or interest on such Notes, and the Issuer must specify whether such Notes are being defeased to maturity or to a particular redemption date;

(2) in the case of Legal Defeasance, the Issuer shall have delivered to the Trustee an Opinion of Counsel reasonably acceptable to the Trustee confirming that, subject to customary assumptions and exclusions,

(a) the Issuer has received from, or there has been published by, the United States Internal Revenue Service a ruling, or

(b) since the issuance of the Notes, there has been a change in the applicable U.S. federal income tax law,

in either case to the effect that, and based thereon such Opinion of Counsel shall confirm that, subject to customary assumptions and exclusions, the Holders of the Notes will not recognize income, gain or loss for U.S. federal income tax purposes, as applicable, as a result of such Legal Defeasance and will be subject to U.S. federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3) in the case of Covenant Defeasance, the Issuer shall have delivered to the Trustee an Opinion of Counsel reasonably acceptable to the Trustee confirming that, subject to customary assumptions and exclusions, the Holders of the Notes will not recognize income, gain or loss for U.S. federal income tax purposes as a result of such Covenant Defeasance and will be subject to such tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4) no Default (other than that resulting from borrowing funds to be applied to make such deposit and any similar and simultaneous deposit relating to other Indebtedness and, in each case, the granting of Liens in connection therewith) shall have occurred and be continuing on the date of such deposit;

(5) such Legal Defeasance or Covenant Defeasance shall not result in a breach or violation of, or constitute a default under any material agreement or instrument (other than the Indenture) to which the Issuer or any Guarantor is a party or by which the Issuer or any Guarantor is bound (other than that resulting from borrowing funds to be applied to make such deposit and any similar and simultaneous deposit relating to other Indebtedness and, in each case, the granting of Liens in connection therewith);

(6) the Issuer shall have delivered to the Trustee an Opinion of Counsel to the effect that, as of the date of such opinion and subject to customary assumptions and exclusions following the deposit, the trust funds will not be subject to the effect of Section 547 of Title 11 of the United States Code;

(7) the Issuer shall have delivered to the Trustee an Officer’s Certificate stating that the deposit was not made by the Issuer with the intent of defeating, hindering, delaying or defrauding any creditors of the Issuer or any Guarantor or others; and

(8) the Issuer shall have delivered to the Trustee an Officer’s Certificate and an Opinion of Counsel (which Opinion of Counsel may be subject to customary assumptions and exclusions) each stating that all conditions precedent provided for or relating to the Legal Defeasance or the Covenant Defeasance, as the case may be, have been complied with.

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Satisfaction and Discharge

The Indenture will be discharged and will cease to be of further effect as to all Notes, when either:

(1) all Notes theretofore authenticated and delivered, except lost, stolen or destroyed Notes which have been replaced or paid and Notes for whose payment money has theretofore been deposited in trust, have been delivered to the Trustee for cancellation; or

(2)(a) all Notes not theretofore delivered to the Trustee for cancellation have become due and payable by reason of the making of a notice of redemption or otherwise, will become due and payable within one year or may be called for redemption within one year under arrangements satisfactory to the Trustee for the giving of notice of redemption by the Trustee in the name, and at the expense, of the Issuer, and the Issuer or any Guarantor has irrevocably deposited or caused to be deposited with the Trustee as trust funds in trust solely for the benefit of the Holders of the Notes, cash in U.S. dollars, Government Securities, or a combination thereof, in such amounts as will be sufficient without consideration of any reinvestment of interest to pay and discharge the entire indebtedness on the Notes not theretofore delivered to the Trustee for cancellation for principal, premium, if any, and accrued interest to the date of maturity or redemption;

(b) no Default (other than that resulting from borrowing funds to be applied to make such deposit and any similar and simultaneous deposit relating to other Indebtedness and, in each case, the granting of Liens in connection therewith) with respect to the Indenture or the Notes shall have occurred and be continuing on the date of such deposit or shall occur as a result of such deposit, and such deposit will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the Indenture) to which the Issuer or any Guarantor is a party or by which the Issuer or any Guarantor is bound (other than that resulting from borrowing funds to be applied to make such deposit and any similar and simultaneous deposit relating to other Indebtedness and, in each case, the granting of Liens in connection therewith);

(c) the Issuer has paid or caused to be paid all sums payable by it under the Indenture; and

(d) the Issuer has delivered irrevocable instructions to the Trustee to apply the deposited money toward the payment of the Notes at maturity or the redemption date, as the case may be.

In addition, the Issuer must deliver an Officer’s Certificate and an Opinion of Counsel to the Trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Amendment, Supplement and Waiver

Except as provided in the next two succeeding paragraphs, the Indenture, any Guarantee and the Notes may be amended or supplemented with the consent of the Holders of at least a majority in principal amount of the outstanding Notes, including consents obtained in connection with a purchase of, or tender offer or exchange offer for, the outstanding Notes, and any existing Default or compliance with any provision of the Indenture, the Notes issued thereunder or any Guarantee may be waived with the consent of the Holders of a majority in principal amount of the outstanding Notes, other than Notes beneficially owned by the Issuer or its Affiliates (including consents obtained in connection with a purchase of or tender offer or exchange offer for the Notes); provided, however, that if any amendment, waiver or other modification will affect only the Cash Pay Notes or Toggle Notes, only the consent of the Holders of at least a majority in principal amount of the then outstanding Cash Pay Notes or Toggle Notes (and not the consent of at least a majority of all Notes), as the case may be, shall be required.

The Indenture provides that, without the consent of each affected Holder of Notes, an amendment or waiver may not, with respect to any Notes held by a non-consenting Holder:

(1) reduce the principal amount of such Notes whose Holders must consent to an amendment, supplement or waiver;

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(2) reduce the principal of or change the fixed final maturity of any such Note or alter or waive the provisions with respect to the redemption of such Notes (other than provisions relating to the covenants described under the caption “Repurchase at the Option of Holders”);

(3) reduce the rate of or change the time for payment of interest on any Note;

(4) waive a Default in the payment of principal of or premium, if any, or interest on the Notes, except a rescission of acceleration of the Notes by the Holders of at least a majority in aggregate principal amount of the Notes and a waiver of the payment default that resulted from such acceleration, or in respect of a covenant or provision contained in the Indenture or any Guarantee which cannot be amended or modified without the consent of all Holders;

(5) make any Note payable in money other than that stated therein;

(6) make any change in the provisions of the Indenture relating to waivers of past Defaults or the rights of Holders to receive payments of principal of or premium, if any, or interest on the Notes;

(7) make any change in these amendment and waiver provisions;

(8) impair the right of any Holder to receive payment of principal of, or interest on such Holder’s Notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such Holder’s Notes;

(9) make any change to or modify the ranking of the Notes that would adversely affect the Holders; or

(10) except as expressly permitted by the Indenture, modify the Guarantees of any Significant Subsidiary in any manner adverse to the Holders of the Notes.

Notwithstanding the foregoing, the Issuer, any Guarantor (with respect to a Guarantee or the Indenture to which it is a party) and the Trustee may amend or supplement the Indenture and any Guarantee or Notes without the consent of any Holder;

(1) to cure any ambiguity, omission, mistake, defect or inconsistency;

(2) to provide for uncertificated Notes of such series in addition to or in place of certificated notes;

(3) to comply with the covenant relating to mergers, consolidations and sales of assets;

(4) to provide for the assumption of the Issuer’s or any Guarantor’s obligations to the Holders;

(5) to make any change that would provide any additional rights or benefits to the Holders or that does not adversely affect the legal rights under the Indenture of any such Holder;

(6) to add covenants for the benefit of the Holders or to surrender any right or power conferred upon the Issuer or any Guarantor;

(7) to comply with requirements of the SEC in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act;

(8) to evidence and provide for the acceptance and appointment under the Indenture of a successor Trustee thereunder pursuant to the requirements thereof;

(9) to provide for the issuance of Exchange Notes or private exchange notes, which are identical to Exchange Notes except that they are not freely transferable;

(10) to add a Guarantor under the Indenture;

(11) to conform the text of the Indenture, Guarantees or the Notes to any provision of this “Description of Notes” to the extent that such provision in this “Description of Notes” was intended to be a verbatim recitation of a provision of the Indenture, Guarantee or Notes;

(12) to make any amendment to the provisions of the Indenture relating to the transfer and legending of Notes as permitted by the Indenture, including, without limitation, to facilitate the issuance and

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administration of the Notes; provided, however, that (i) compliance with the Indenture as so amended would not result in Notes being transferred in violation of the Securities Act or any applicable securities law and (ii) such amendment does not materially and adversely affect the rights of Holders to transfer Notes; or

(13) to mortgage, pledge, hypothecate or grant any other Lien in favor of the Trustee for the benefit of the Holders of the Notes, as security for the payment and performance of all or any portion of the Obligations, in any property or assets.

The consent of the Holders is not necessary under the Indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment.

Notices

Notices given by publication will be deemed given on the first date on which publication is made and notices given by first-class mail, postage prepaid, will be deemed given five calendar days after mailing.

Concerning the Trustee

The Indenture contains certain limitations on the rights of the Trustee thereunder, should it become a creditor of the Issuer, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest it must eliminate such conflict within 90 days, apply to the SEC for permission to continue or resign.

The Indenture provides that the Holders of a majority in principal amount of the outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the Trustee, subject to certain exceptions. The Indenture provides that in case an Event of Default shall occur (which shall not be cured), the Trustee will be required, in the exercise of its power, to use the degree of care of a prudent person in the conduct of his own affairs. Subject to such provisions, the Trustee will be under no obligation to exercise any of its rights or powers under the Indenture at the request of any Holder of the Notes, unless such Holder shall have offered to the Trustee security and indemnity satisfactory to it against any loss, liability or expense.

Governing Law

The Indenture, the Notes and the Guarantees are governed by and construed in accordance with the laws of the State of New York.

Certain Definitions

Set forth below are certain defined terms used in the Indenture. For purposes of the Indenture, unless otherwise specifically indicated, the term “consolidated” with respect to any Person refers to such Person on a consolidated basis in accordance with GAAP, but excluding from such consolidation any Unrestricted Subsidiary as if such Unrestricted Subsidiary were not an Affiliate of such Person.

“Acquired Indebtedness” means, with respect to any specified Person,

(1) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Restricted Subsidiary of such specified Person, including Indebtedness incurred in connection with, or in contemplation of, such other Person merging with or into or becoming a Restricted Subsidiary of such specified Person, and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

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“Additional Interest” means all additional interest then owing pursuant to the Registration Rights Agreement.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control” (including, with correlative meanings, the terms “controlling,” “controlled by” and “under common control with”), as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise.

“Applicable Premium” means, with respect to any Note on any Redemption Date, the greater of:

(1) 1.0% of the principal amount of such Note; and

(2)(A) with respect to the Toggle Notes, the excess, if any, of (a) the present value at such Redemption Date of (i) the redemption price of such Toggle Note at November 1, 2012 (such redemption price being set forth in the table appearing under the caption “Optional Redemption—Toggle Notes”), plus (ii) all required interest payments (calculated based on the cash interest rate payable on the Toggle Notes) due on such Toggle Note through November 1, 2012 (excluding accrued but unpaid interest to the Redemption Date), computed using a discount rate equal to the Treasury Rate as of such Redemption Date plus 50 basis points; over (b) the principal amount of such Toggle Note, or

(B) with respect to the Cash Pay Notes, the excess, if any, of (a) the present value at such Redemption Date of (i) the redemption price of such Cash Pay Note at November 1, 2012 (such redemption price being set forth in the tables appearing under the caption “Optional Redemption—Cash Pay Notes”), plus (ii) all required interest payments due on such Cash Pay Note through November 1, 2012 (excluding accrued but unpaid interest to the Redemption Date), computed using a discount rate equal to the Treasury Rate as of such Redemption Date plus 50 basis points; over (b) the principal amount of such Cash Pay Note.

“Asset Sale” means:

(1) the sale, conveyance, transfer or other disposition, whether in a single transaction or a series of related transactions, of property or assets (including by way of a Sale and Lease-Back Transaction) of the Issuer or any of its Restricted Subsidiaries (each referred to in this definition as a “disposition”); or

(2) the issuance or sale of Equity Interests of any Restricted Subsidiary, whether in a single transaction or a series of related transactions (other than Preferred Stock of Restricted Subsidiaries issued in compliance with the covenant described under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”);

in each case, other than:

(a) any disposition of Cash Equivalents or Investment Grade Securities or obsolete or worn out equipment (including any such equipment that has been refurbished in contemplation of such disposition) in the ordinary course of business or any disposition of inventory or goods (or other assets) held for sale in the ordinary course of business;

(b) the disposition of all or substantially all of the assets of the Issuer in a manner permitted pursuant to the provisions described under “Certain Covenants—Merger, Consolidation or Sale of All or Substantially All Assets” or any disposition that constitutes a Change of Control pursuant to the Indenture;

(c) the making of any Restricted Payment or Permitted Investment that is permitted to be made, and is made, under the covenant described under “Certain Covenants—Limitation on Restricted Payments”;

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(d) any disposition of assets or issuance or sale of Equity Interests of any Restricted Subsidiary in any transaction or series of related transactions with an aggregate fair market value of less than $75.0 million;

(e) any disposition of property or assets or issuance of securities by a Restricted Subsidiary of the Issuer to the Issuer or by the Issuer or a Restricted Subsidiary of the Issuer to another Restricted Subsidiary of the Issuer;

(f) to the extent allowable under Section 1031 of the Code or any comparable or successor provision, any exchange of like property (excluding any boot thereon) for use in a Similar Business;

(g) the lease, assignment or sub-lease of any real or personal property in the ordinary course of business;

(h)(i) any issuance or sale of Equity Interests in, or Indebtedness or other securities of, an Unrestricted Subsidiary (other than an Oncor Subsidiary) and (ii) up to $1,250.0 million of aggregate Net Proceeds from the sale of Equity Interests in, or Indebtedness or other securities of, any of the Oncor Subsidiaries; provided that such $1,250.0 million of Net Proceeds are used to reduce intercompany loans from TCEH outstanding at the time such Net Proceeds are received and required to be repaid therefrom);

(i) foreclosures on assets;

(j) sales of accounts receivable, or participations therein, in connection with any Receivables Facility for the benefit of the Issuer or any of its Restricted Subsidiaries;

(k) any financing transaction with respect to property built or acquired by the Issuer or any Restricted Subsidiary after the Closing Date, including Sale and Lease-Back Transactions and asset securitizations permitted by the Indenture;

(l) [Intentionally omitted];

(m) sales, transfers and other dispositions (i) of Investments in joint ventures to the extent required by, or made pursuant to, customary buy/sell or put/call arrangements between the joint venture parties set forth in joint venture arrangements and similar binding arrangements or (ii) to joint ventures in connection with the dissolution or termination of a joint venture to the extent required pursuant to joint venture and similar arrangements;

(n) [Intentionally omitted];

(o) [Intentionally omitted];

(p) [Intentionally omitted];

(q) any Casualty Event provided the net proceeds therefrom are deemed to be Net Proceeds and are applied in accordance with the second paragraph under “Repurchase at the Option of Holders— Asset Sales” or the Issuer or such Restricted Subsidiary delivers to the Trustee a Restoration Certificate with respect to plans to invest (and reinvests within 450 days from the date of receipt of the Net Proceeds);

(r) the execution of (or amendment to), settlement of or unwinding of any Hedging Obligation in the ordinary course of business;

(s) any disposition of mineral rights (other than coal and lignite mineral rights); provided the net proceeds therefrom are deemed to be Net Proceeds and are applied in accordance with the second paragraph under “Repurchase at the Option of Holders—Asset Sales”;

(t) any sale, transfer or other disposal of any real property that is (i) primarily used or intended to be used for mining which has either been reclaimed, or has not been used for mining in a manner which requires reclamation, and in either case has been determined by TCEH not to be necessary for use for

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mining, (ii) used as buffer land, but no longer serves such purpose or its use is restricted such that it will continue to be buffer land, or (iii) was acquired in connection with power generation facilities, but has been determined by TCEH to no longer be commercially suitable for such purpose;

(u) [Intentionally omitted];

(v) dispositions of power, capacity, heat rate, renewable energy credits, waste by-products, energy, electricity, coal and lignite, oil and other petroleum based liquids, emissions and other environmental credits, ancillary services, fuel (including all forms of nuclear fuel and natural gas) and other related assets or products of services, including assets related to trading activities or the sale of inventory or contracts related to any of the foregoing, in each case in the ordinary course of business;

(w) [Intentionally omitted];

(x) any disposition of assets in connection with salvage activities; provided the net proceeds therefrom are deemed to be Net Proceeds and are applied in accordance with the second paragraph under “Repurchase at the Option of Holders—Asset Sales”; and

(y) any sale, transfer or other disposition of any assets required by any Government Authority, provided the net proceeds therefrom are deemed to be Net Proceeds and are applied in accordance with the second paragraph under “Repurchase at the Option of Holders—Asset Sales.”

“Asset Sale Offer” has the meaning set forth in the fourth paragraph under “Repurchase at the Option of Holders—Asset Sales.”

“Bankruptcy Code” means Title 11 of the United States Code, as amended.

“Bankruptcy Law” means the Bankruptcy Code and any similar federal, state or foreign law for the relief of debtors.

“Business Day” means each day which is not a Legal Holiday.

“Capital Stock” means:

(1) in the case of a corporation, corporate stock;

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited); and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person.

“Capitalized Lease Obligation” means, at the time any determination thereof is to be made, the amount of the liability in respect of a capital lease that would at such time be required to be capitalized and reflected as a liability on a balance sheet (excluding the footnotes thereto) in accordance with GAAP; provided that any obligations existing on the Closing Date (i) that were not included on the balance sheet of the Issuer as capital lease obligations and (ii) that are subsequently recharacterized as capital lease obligations due to a change in accounting treatment shall for all purposes not be treated as Capitalized Lease Obligations.

“Capitalized Software Expenditures” means, for any period, the aggregate of all expenditures (whether paid in cash or accrued as liabilities) by a Person and its Restricted Subsidiaries during such period in respect of purchased software or internally developed software and software enhancements that, in conformity with GAAP, are or are required to be reflected as capitalized costs on the consolidated balance sheet of a Person and its Restricted Subsidiaries.

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“Cash Equivalents” means:

(1) United States dollars;

(2) euros or any national currency of any participating member state of the EMU or such local currencies held by the Issuer and its Restricted Subsidiaries from time to time in the ordinary course of business;

(3) securities issued or directly and fully and unconditionally guaranteed or insured by the U.S. government (or any agency or instrumentality thereof the securities of which are unconditionally guaranteed as a full faith and credit obligation of the U.S. government) with maturities, unless such securities are deposited to defease Indebtedness, of 24 months or less from the date of acquisition;

(4) certificates of deposit, time deposits and eurodollar time deposits with maturities of one year or less from the date of acquisition, bankers’ acceptances with maturities not exceeding one year and overnight bank deposits, in each case with any commercial bank having capital and surplus of not less than $500.0 million in the case of U.S. banks and $100.0 million (or the U.S. dollar equivalent as of the date of determination) in the case of non-U.S. banks;

(5) repurchase obligations for underlying securities of the types described in clauses (3) and (4) entered into with any financial institution meeting the qualifications specified in clause (4) above;

(6) commercial paper rated at least P-1 by Moody’s or at least A-1 by S&P and in each case maturing within 24 months after the date of creation thereof;

(7) marketable short-term money market and similar securities having a rating of at least P-2 or A-2 from either Moody’s or S&P, respectively (or, if at any time neither Moody’s nor S&P shall be rating such obligations, an equivalent rating from another Rating Agency) and in each case maturing within 24 months after the date of creation thereof;

(8) investment funds investing 95% of their assets in securities of the types described in clauses (1) through (7) above;

(9) readily marketable direct obligations issued by any state, commonwealth or territory of the United States or any political subdivision or taxing authority thereof having an Investment Grade Rating from either Moody’s or S&P with maturities of 24 months or less from the date of acquisition;

(10) Indebtedness or Preferred Stock issued by Persons with a rating of A or higher from S&P or A2 or higher from Moody’s with maturities of 24 months or less from the date of acquisition; and

(11) Investments with average maturities of 24 months or less from the date of acquisition in money market funds rated AAA- (or the equivalent thereof) or better by S&P or Aaa3 (or the equivalent thereof) or better by Moody’s.

Notwithstanding the foregoing, Cash Equivalents shall include amounts denominated in currencies other than those set forth in clauses (1) and (2) above; provided that such amounts are converted into any currency listed in clauses (1) and (2) as promptly as practicable and in any event within ten Business Days following the receipt of such amounts.

“Cash Interest” has the meaning set forth under “Principal, Maturity and Interest—Toggle Notes.”

“Casualty Event” means any taking under power of eminent domain or similar proceeding and any insured loss; provided that any such taking or similar proceeding or insured loss that results in Net Proceeds of less than $75.0 million shall not be deemed a Casualty Event.

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“Change of Control” means the occurrence of any of the following:

(1) the sale, lease or transfer, in one or a series of related transactions, of all or substantially all of the assets of the Issuer and its Subsidiaries, taken as a whole, to any Person other than a Permitted Holder; or

(2) the Issuer becomes aware (by way of a report or any other filing pursuant to Section 13(d) of the Exchange Act, proxy, vote, written notice or otherwise) of the acquisition by any Person or group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act or any successor provision), including any group acting for the purpose of acquiring, holding or disposing of securities (within the meaning of Rule 13d-5(b)(1) under the Exchange Act or any successor provision), other than the Permitted Holders, in a single transaction or in a related series of transactions, by way of merger, consolidation or other business combination or purchase of beneficial ownership (within the meaning of Rule 13d-3 under the Exchange Act, or any successor provision) of 50% or more of the total voting power of the Voting Stock of the Issuer or any of its direct or indirect parent companies.

“Closing Date” means October 10, 2007.

“Code” means the Internal Revenue Code of 1986, as amended, or any successor thereto.

“Collateral Posting Facility” means any senior cash posting credit facility, the size of which is capped by the mark-to-market loss, inclusive of any unpaid settlement amounts, of TCEH and its subsidiaries on a hypothetical portfolio of commodity swaps, forwards, and futures transactions that correspond to or replicate all or a portion of actual transactions by TCEH and its subsidiaries that are outstanding on, or entered into from time to time on or after the Closing Date.

“Consolidated Depreciation and Amortization Expense” means with respect to any Person for any period, the total amount of depreciation and amortization expense, including the amortization of deferred financing fees, nuclear fuel costs, depletion of coal or lignite reserves, debt issuance costs, commissions, fees and expenses and Capitalized Software Expenditures, of such Person and its Restricted Subsidiaries for such period on a consolidated basis and otherwise determined in accordance with GAAP.

“Consolidated Interest Expense” means, with respect to any Person for any period, without duplication, the sum of:

(1) consolidated interest expense of such Person and its Restricted Subsidiaries for such period, to the extent such expense was deducted (and not added back) in computing Consolidated Net Income (including (a) amortization of original issue discount resulting from the issuance of Indebtedness at less than par, (b) all commissions, discounts and other fees and charges owed with respect to letters of credit, bankers’ acceptances or any Collateral Posting Facility or similar facilities, (c) non-cash interest payments (but excluding any non-cash interest expense attributable to the movement in the mark to market valuation of Hedging Obligations or other derivative instruments pursuant to GAAP), (d) the interest component of Capitalized Lease Obligations, and (e) net payments, if any, pursuant to interest rate Hedging Obligations with respect to Indebtedness, and excluding (u) accretion of asset retirement obligations and accretion or accrual of discounted liabilities not constituting Indebtedness, (v) any expense resulting from the discounting of the Existing Notes or other Indebtedness in connection with the application of purchase accounting, (w) any Additional Interest and any comparable “additional interest” with respect to other securities, (x) amortization of reacquired Indebtedness, deferred financing fees, debt issuance costs, commissions, fees and expenses, (y) any expensing of bridge, commitment and other financing fees and (z) commissions, discounts, yield and other fees and charges (including any interest expense) related to any Receivables Facility); plus

(2) consolidated capitalized interest of such Person and its Restricted Subsidiaries for such period, whether paid or accrued; less

(3) interest income of such Person and its Restricted Subsidiaries for such period.

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For purposes of this definition, interest on a Capitalized Lease Obligation shall be deemed to accrue at an interest rate reasonably determined by such Person to be the rate of interest implicit in such Capitalized Lease Obligation in accordance with GAAP.

“Consolidated Leverage Ratio” as of any date of determination, means the ratio of (x) Consolidated Total Indebtedness of the Issuer computed as of the end of the most recent fiscal quarter for which internal financial statements are available immediately preceding the date on which such event for which such calculation is being made shall occur to (y) the aggregate amount of EBITDA of the Issuer for the period of the most recently ended four full consecutive fiscal quarters for which internal financial statements are available immediately preceding the date on which such event for which such calculation is being made shall occur, in each case with such pro forma adjustments to Consolidated Total Indebtedness and EBITDA as are appropriate and consistent with the pro forma adjustment provisions set forth in the definition of “Fixed Charge Coverage Ratio.”

“Consolidated Net Income” means, with respect to any Person for any period, the aggregate of the Net Income of such Person for such period, on a consolidated basis, and otherwise determined in accordance with GAAP; provided, however, that, without duplication,

(1) any after-tax effect of extraordinary, non-recurring or unusual gains or losses (less all fees and expenses relating thereto) or expenses (including Transaction fees and expenses to the extent incurred on or prior to December 31, 2008), severance, relocation costs, consolidation and closing costs, integration and facilities opening costs, business optimization costs, transition costs, restructuring costs, signing, retention or completion bonuses, and curtailments or modifications to pension and post-retirement employee benefit plans shall be excluded;

(2) the cumulative effect of a change in accounting principles during such period shall be excluded;

(3) any after-tax effect of income (loss) from disposed, abandoned or discontinued operations and any net after-tax gains or losses on disposal of disposed, abandoned, transferred, closed or discontinued operations shall be excluded;

(4) any after-tax effect of gains or losses (less all fees and expenses relating thereto) attributable to asset dispositions or abandonments other than in the ordinary course of business, as determined in good faith by the Issuer, shall be excluded;

(5) the Net Income for such period of any Person that is (a) is not a Subsidiary, (b) an Unrestricted Subsidiary or (c) is accounted for by the equity method of accounting shall be excluded; provided that Consolidated Net Income of the Issuer shall be increased by the amount of dividends or distributions or other payments that are actually paid in cash (or to the extent converted into cash) to the referent Person or a Restricted Subsidiary thereof in respect of such period;

(6) solely for the purpose of determining the amount available for Restricted Payments under clause (3)(a) of the first paragraph of “Certain Covenants—Limitation on Restricted Payments,” the Net Income for such period of any Restricted Subsidiary (other than any Guarantor) shall be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of its Net Income is not at the date of determination wholly permitted without any prior governmental approval (which has not been obtained) or, directly or indirectly, by the operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule, or governmental regulation applicable to that Restricted Subsidiary or its stockholders, unless such restriction with respect to the payment of dividends or similar distributions has been legally waived or is otherwise permitted by the covenant described under “Certain Covenants—Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries”; provided that Consolidated Net Income of the Issuer will be increased by the amount of dividends or other distributions or other payments actually paid in cash (or to the extent converted into cash) or Cash Equivalents to the Issuer or a Restricted Subsidiary thereof in respect of such period, to the extent not already included therein;

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(7) effects of all adjustments (including the effects of such adjustments pushed down to the Issuer and its Restricted Subsidiaries) in such Person’s consolidated financial statements pursuant to GAAP resulting from the application of purchase accounting in relation to the Transactions or any consummated acquisition or the amortization or write-off of any amounts thereof, net of taxes, shall be excluded;

(8) any net after-tax effect of income (loss) attributable to the early extinguishment of Indebtedness (other than Hedging Obligations) shall be excluded;

(9) any impairment charge or asset write-off, including, without limitation, impairment charges or asset write-offs related to intangible assets, long-lived assets or investments in debt and equity securities, in each case, pursuant to GAAP and the amortization of intangibles arising pursuant to GAAP shall be excluded;

(10) any non-cash compensation expense recorded from grants of stock appreciation or similar rights, stock options, restricted stock or other rights, and any cash charges associated with the rollover, acceleration or payout of Equity Interests by management of the Issuer or any of its direct or indirect parent companies in connection with the Transactions, shall be excluded;

(11) any fees and expenses incurred during such period, or any amortization thereof for such period, in connection with any acquisition, Investment, Asset Sale, issuance or repayment of Indebtedness, issuance of Equity Interests, refinancing transaction or amendment or modification of any debt instrument (in each case, including any such transaction consummated prior to the Closing Date and any such transaction undertaken but not completed) and any charges or non-recurring merger costs incurred during such period as a result of any such transaction shall be excluded;

(12) accruals and reserves that are established or adjusted within twelve months after the Closing Date that are so required to be established as a result of the Transactions in accordance with GAAP, or changes as a result of adoption or modification of accounting policies, shall be excluded;

(13) to the extent covered by insurance and actually reimbursed, or, so long as the Issuer has made a determination that there exists reasonable evidence that such amount will in fact be reimbursed by the insurer and only to the extent that such amount is (a) not denied by the applicable carrier in writing within 180 days and (b) in fact reimbursed within 365 days of the date of such evidence (with a deduction for any amount so added back to the extent not so reimbursed within 365 days), expenses with respect to liability or casualty events or business interruption shall be excluded;

(14) any net after-tax effect of unrealized income (loss) attributable to Hedging Obligations or other derivative instruments shall be excluded; and

(15) any benefit from any fair market value of any contract as recorded on the balance sheet at the time of the Transactions shall be excluded.

Notwithstanding the foregoing, for the purpose of the covenant described under “Certain Covenants—Limitation on Restricted Payments” only (other than clause (3)(d) thereof), there shall be excluded from Consolidated Net Income any income arising from any sale or other disposition of Restricted Investments made by the Issuer and its Restricted Subsidiaries, any repurchases and redemptions of Restricted Investments from the Issuer and its Restricted Subsidiaries, any repayments of loans and advances which constitute Restricted Investments by the Issuer or any of its Restricted Subsidiaries, any sale of the stock of an Unrestricted Subsidiary or any distribution or dividend from an Unrestricted Subsidiary, in each case only to the extent such amounts increase the amount of Restricted Payments permitted under such covenant pursuant to clause (3)(d) thereof.

“Consolidated Secured Debt Ratio” means, as of any date of determination, the ratio of (x) Consolidated Secured Indebtedness computed as of the end of the most recent fiscal quarter for which internal financial statements are available immediately preceding the date on which such event for which such calculation is being made shall occur to (y) the aggregate amount of EBITDA of the Issuer for the period of the most recently ended four full consecutive fiscal quarters for which internal financial statements are available immediately preceding

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the date on which such event for which such calculation is being made shall occur, in each case with such pro forma adjustments to Consolidated Secured Indebtedness and EBITDA as are appropriate and consistent with the pro forma adjustment provisions set forth in the definition of “Fixed Charge Coverage Ratio.”

“Consolidated Secured Indebtedness” means Consolidated Total Indebtedness secured by a Lien on any assets of the Issuer or any of its Restricted Subsidiaries.

“Consolidated Total Indebtedness” means, as at any date of determination, an amount equal to (1) the aggregate amount of all outstanding Indebtedness of the Issuer and its Restricted Subsidiaries on a consolidated basis consisting of Indebtedness for borrowed money, debt obligations evidenced by promissory notes and similar instruments, letters of credit (only to the extent of any unreimbursed drawings thereunder) and Obligations in respect of Capitalized Lease Obligations, plus (2) the aggregate amount of all outstanding Disqualified Stock of the Issuer and all Disqualified Stock and Preferred Stock of its Restricted Subsidiaries on a consolidated basis, with the amount of such Disqualified Stock and Preferred Stock equal to the greater of their respective voluntary or involuntary liquidation preferences and maximum fixed repurchase prices, in each case determined on a consolidated basis in accordance with GAAP, less (3) the aggregate amount of all Unrestricted Cash and less (4) all Deposit L/C Loans and Incremental Deposit L/C Loans outstanding on such date of determination. For purposes hereof, the “maximum fixed repurchase price” of any Disqualified Stock or Preferred Stock that does not have a fixed repurchase price shall be calculated in accordance with the terms of such Disqualified Stock or Preferred Stock as if such Disqualified Stock or Preferred Stock were purchased on any date on which Consolidated Total Indebtedness shall be required to be determined, and if such price is based upon, or measured by, the fair market value of such Disqualified Stock or Preferred Stock, such fair market value shall be determined reasonably and in good faith by the Issuer.

“Contingent Obligations” means, with respect to any Person, any obligation of such Person guaranteeing any leases, dividends or other obligations that do not constitute Indebtedness (“primary obligations”) of any other Person (the “primary obligor”) in any manner, whether directly or indirectly, including, without limitation, any obligation of such Person, whether or not contingent,

(1) to purchase any such primary obligation or any property constituting direct or indirect security therefor,

(2) to advance or supply funds

(a) for the purchase or payment of any such primary obligation, or

(b) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor, or

(3) to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such primary obligation against loss in respect thereof.

“Covered Commodity” means any energy, electricity, generation capacity, power, heat rate, congestion, natural gas, nuclear fuel (including enrichment and conversion), diesel fuel, fuel oil, other petroleum-based liquids, coal, lignite, weather, emissions and other environmental credits, waste by-products renewable energy credit, or any other energy related commodity or service (including ancillary services and related risks (such as location basis)).

“Credit Facilities” means, with respect to the Issuer or any of its Restricted Subsidiaries, one or more debt facilities, including the TCEH Senior Secured Facilities or other financing arrangements (including, without limitation, commercial paper facilities or indentures) providing for revolving credit loans, term loans, letters of credit or other long-term indebtedness, including any notes, mortgages, guarantees, collateral documents, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications,

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extensions, renewals, restatements or refundings thereof and any indentures or credit facilities or commercial paper facilities that replace, refund or refinance any part of the loans, notes, other credit facilities or commitments thereunder, including any such replacement, refunding or refinancing facility or indenture that increases the amount permitted to be borrowed thereunder or alters the maturity thereof (provided that such increase in borrowings is permitted by the covenant described under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”) or adds Restricted Subsidiaries as additional borrowers or guarantors thereunder and whether by the same or any other agent, lender or group of lenders.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Deposit L/C Loan” means Deposit L/C Loans under, and as defined in, the TCEH Senior Secured Facilities.

“Designated Non-cash Consideration” means the fair market value of non-cash consideration received by the Issuer or a Restricted Subsidiary in connection with an Asset Sale that is so designated as Designated Non-cash Consideration pursuant to an Officer’s Certificate, setting forth the basis of such valuation, executed by the principal financial officer of the Issuer, less the amount of cash or Cash Equivalents received in connection with a subsequent sale of or collection on such Designated Non-cash Consideration.

“Designated Preferred Stock” means Preferred Stock of the Issuer or any parent corporation thereof (in each case other than Disqualified Stock) that is issued for cash (other than to a Restricted Subsidiary or an employee stock ownership plan or trust established by the Issuer or any of its Subsidiaries) and is so designated as Designated Preferred Stock, pursuant to an Officer’s Certificate executed by the principal financial officer of the Issuer or the applicable parent corporation thereof, as the case may be, on the issuance date thereof, the cash proceeds of which are excluded from the calculation set forth in clause (3) of the first paragraph under “Certain Covenants—Limitation on Restricted Payments.”

“Disqualified Stock” means, with respect to any Person, any Capital Stock of such Person which, by its terms, or by the terms of any security into which it is convertible or for which it is putable or exchangeable, or upon the happening of any event, matures or is mandatorily redeemable (other than solely as a result of a change of control or asset sale) pursuant to a sinking fund obligation or otherwise, or is redeemable at the option of the holder thereof (other than solely as a result of a change of control or asset sale), in whole or in part, in each case prior to the date 91 days after the earlier of the maturity date of the Notes or the date the Notes are no longer outstanding; provided, however, that if such Capital Stock is issued to any plan for the benefit of employees of the Issuer or its Subsidiaries or by any such plan to such employees, such Capital Stock shall not constitute Disqualified Stock solely because it may be required to be repurchased by the Issuer or its Subsidiaries in order to satisfy applicable statutory or regulatory obligations.

“EBITDA” means, with respect to any Person for any period, the Consolidated Net Income of such Person for such period

(1) increased (without duplication) by:

(a) provision for taxes based on income or profits or capital gains, including, without limitation, foreign, federal, state, franchise, excise, value-added and similar taxes and foreign withholding taxes (including penalties and interest related to such taxes or arising from tax examinations) of such Person paid or accrued during such period, deducted (and not added back) in computing Consolidated Net Income; plus

(b) Fixed Charges of such Person for such period (including (x) net losses on Hedging Obligations or other derivative instruments entered into for the purpose of hedging interest rate risk and (y) costs of

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surety bonds in connection with financing activities, in each case, to the extent included in Fixed Charges), together with items excluded from the definition of “Consolidated Interest Expense” pursuant to clauses (1)(u), (v), (w), (x), (y) and (z) of the definition thereof, and, in each such case, to the extent the same were deducted (and not added back) in calculating such Consolidated Net Income; plus

(c) Consolidated Depreciation and Amortization Expense of such Person for such period to the extent the same was deducted (and not added back) in computing Consolidated Net Income; plus

(d) any fees, expenses or charges (other than depreciation or amortization expense) related to any Equity Offering, Permitted Investment, acquisition, disposition, recapitalization or the incurrence of Indebtedness permitted to be incurred by such Person and its Restricted Subsidiaries, by the Indenture (including a refinancing transaction or amendment or other modification of any debt instrument) (whether or not successful), including (i) such fees, expenses or charges related to the offering of the Notes, the offering of the TCEH Notes and any interim bridge facilities related thereto and the TCEH Senior Secured Facilities and any Receivables Facility, (ii) any amendment or other modification of the Notes, (iii) any such transaction consummated prior to the Closing Date and any such transaction undertaken but not completed and (iv) any charges or non-recurring merger costs as a result of any such transaction, in each case, deducted (and not added back) in computing Consolidated Net Income; plus

(e) the amount of any restructuring charge or reserve deducted (and not added back) in such period in computing Consolidated Net Income, including any costs incurred in connection with acquisitions after the Closing Date, costs related to the closure and/or consolidation of facilities; plus

(f) any other non-cash charges, including any write-offs or write-downs, reducing Consolidated Net Income for such period (provided that if any such non-cash charges represent an accrual or reserve for potential cash items in any future period, the cash payment in respect thereof in such future period shall be subtracted from EBITDA to such extent, and excluding amortization of a prepaid cash item that was paid in a prior period); plus

(g) the amount of any minority interest expense consisting of Subsidiary income attributable to minority equity interests of third parties in any non-Wholly Owned Subsidiary deducted (and not added back) in such period in calculating Consolidated Net Income; plus

(h) the amount of management, monitoring, consulting and advisory fees and related indemnities and expenses paid in such period to the Investors to the extent otherwise permitted under “Certain Covenants—Transactions with Affiliates” and deducted (and not added back) in calculating Consolidated Net Income; plus

(i) the amount of net cost savings projected by the Issuer in good faith to be realized as a result of specified actions taken or to be taken prior to or during such period (calculated on a pro forma basis as though such cost savings had been realized on the first day of such period and added to EBITDA until fully realized), net of the amount of actual benefits realized during such period from such actions; provided that (w) such cost savings are reasonably identifiable and factually supportable, (x) such actions have been taken or are to be taken within 12 months after the date of determination to take such action and some portion of the benefit is expected to be realized within 12 months of taking such action, (y) no cost savings shall be added pursuant to this clause (i) to the extent duplicative of any expenses or charges relating to such cost savings that are included in clause (e) above with respect to such period and (z) the aggregate amount of cost savings added pursuant to this clause (i) shall not exceed $150.0 million for any four consecutive quarter period (which adjustments may be incremental to pro forma adjustments made pursuant to the second paragraph of the definition of “Fixed Charge Coverage Ratio”); plus

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(j) the amount of loss on sales of receivables and related assets to the Receivables Subsidiary in connection with a Receivables Facility deducted (and not added back) in calculating Consolidated Net Income; plus

(k) any costs or expense incurred by the Issuer or a Restricted Subsidiary pursuant to any management equity plan or stock option plan or any other management or employee benefit plan or agreement or any stock subscription or shareholder agreement, to the extent that such cost or expenses are funded with cash proceeds contributed to the capital of the Issuer or net cash proceeds of an issuance of Equity Interests (other than Disqualified Stock) of the Issuer (or any direct or indirect parent thereof) solely to the extent that such net cash proceeds are excluded from the calculation set forth in clause (3) of the first paragraph under “Certain Covenants—Limitation on Restricted Payments”; plus

(l) Expenses Relating to a Unit Outage; provided that the only Expenses Relating to a Unit Outage that may be included in EBITDA shall be, without duplication (i) up to $250.0 million per fiscal year of Expenses Relating to a Unit Outage incurred within the first 12 months after any planned or unplanned outage of any Unit by reason of any action by any regulatory body or other Government Authority or to comply with any applicable law and (ii) up to $100.0 million per fiscal year of Expenses Relating to a Unit Outage incurred within the first 12 months after any planned outage of any Unit for purposes of expanding or upgrading such Unit; plus

(m) cash receipts (or any netting arrangements resulting in increased cash receipts) not added in arriving at EBITDA or Consolidated Net Income in any period to the extent the non-cash gains relating to such receipts were deducted in the calculation of EBITDA pursuant to paragraph (2) below for any previous period and not added; and

(2) decreased by (without duplication) (a) non-cash gains increasing Consolidated Net Income of such Person for such period, excluding any non-cash gains to the extent they represent the reversal of an accrual or reserve for a potential cash item that reduced EBITDA in any prior period, (b) cash expenditures (or any netting arrangements resulting in increased cash expenditures) not deducted in arriving at EBITDA or Consolidated Net Income in any period to the extent non-cash losses relating to such expenditures were added in the calculation of EBITDA pursuant to paragraph (1) above for any previous period and not deducted, and (c) the amount of any minority interest income consisting of Subsidiary losses attributable to minority equity interests of third parties in any non-Wholly Owned Subsidiary to the extent such minority interest income is included in Consolidated Net Income.

“EFH Senior Interim Facility” means the interim loan agreement, dated as of the Closing Date by and among the Issuer, as borrower, Energy Future Competitive Holdings and Energy Future Intermediate Holding, as guarantors, the lenders party thereto in their capacities as lenders thereunder and Morgan Stanley Senior Funding, Inc., as Administrative Agent, including any guarantees, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications or restatements thereof.

“EMU” means the economic and monetary union as contemplated in the Treaty on European Union.

“Environmental CapEx Debt” means Indebtedness of the Issuer or any of its Restricted Subsidiaries incurred for the purpose of financing Environmental Capital Expenditures.

“Energy Future Competitive Holdings” means Energy Future Competitive Holdings Company.

“Energy Future Intermediate Holding” means Energy Future Intermediate Holding Company LLC.

“Environmental Capital Expenditures” means capital expenditures deemed necessary by the Issuer or its Restricted Subsidiaries to comply with, or in anticipation of having to comply with, Environmental Law or

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otherwise undertaken voluntarily by the Issuer or any of its Restricted Subsidiaries in connection with environmental matters.

“Environmental Law” means any applicable Federal, state, foreign or local statute, law, rule, regulation, ordinance, code and rule of common law now or hereafter in effect and in each case as amended, and any applicable judicial or administrative interpretation thereof, including any applicable judicial or administrative order, consent decree or judgment, relating to the environment, human health or safety or Hazardous Materials.

“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock, but excluding any debt security that is convertible into, or exchangeable for, Capital Stock.

“Equity Offering” means any public or private sale of common stock or Preferred Stock of the Issuer or any of its direct or indirect parent companies (excluding Disqualified Stock), other than:

(1) public offerings with respect to the Issuer’s or any direct or indirect parent company’s common stock registered on Form S-8;

(2) issuances to any Subsidiary of the Issuer; and

(3) any such public or private sale that constitutes an Excluded Contribution.

“ERCOT” means the Electric Reliability Council of Texas.

“euro” means the single currency of participating member states of the EMU.

“Event of Default” has the meaning set forth under “Events of Default and Remedies.”

“Excess Proceeds” has the meaning set forth in the fourth paragraph under “Repurchase at the Option of Holders—Asset Sales.”

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Exchange Notes” means any notes issued in exchange for the Notes pursuant to the Registration Rights Agreement or similar agreement.

“Excluded Contribution” means net cash proceeds, marketable securities or Qualified Proceeds received by the Issuer after the Closing Date from

(1) contributions to its common equity capital, and

(2) the sale (other than to a Subsidiary of the Issuer or to any management equity plan or stock option plan or any other management or employee benefit plan or agreement of the Issuer) of Capital Stock (other than Disqualified Stock and Designated Preferred Stock) of the Issuer,

in each case designated as Excluded Contributions pursuant to an Officer’s Certificate executed by the principal financial officer of the Issuer on the date such capital contributions are made or the date such Equity Interests are sold, as the case may be, which are excluded from the calculation set forth in clause (3) of the first paragraph under “Certain Covenants—Limitation on Restricted Payments.”

“Existing Notes” means

• Energy Future Holdings Corp. 5.55% Fixed Senior Notes Series P due 2014;

• Energy Future Holdings Corp. 6.50% Fixed Senior Notes Series Q due 2024;

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• Energy Future Holdings Corp. 6.55% Fixed Senior Notes Series R due 2034;

• Energy Future Holdings Corp. 6.375% Series C Senior Notes due 2008;

• Energy Future Holdings Corp. Floating Convertible Senior Notes due 2033;

• Energy Future Competitive Holdings Floating Rate Junior Subordinated Debentures, Series D due 2037;

• Energy Future Competitive Holdings 8.175% Fixed Junior Subordinated Debentures, Series E due 2037;

• Portion of Energy Future Holdings Corp. 4.80% Series O Senior Notes due 2009 not tendered;

• Portion of TCEH 6.125% Senior Notes due 2008 not tendered;

• Portion of TCEH 7.000% Senior Notes due 2013 not tendered;

• Energy Future Competitive Holdings 7.460% Fixed Secured Bonds with amortizing payments to 2015;

• Energy Future Competitive Holdings 9.580% Fixed Notes due in semi-annual installments to 2019;

• Energy Future Competitive Holdings 8.254% Fixed Notes due in quarterly installments to 2021;

Pollution Control Revenue Bonds—Brazos River Authority:

• 5.400% Fixed Series 1994A due May 1, 2029;

• 7.700% Fixed Series 1999A due April 1, 2033;

• 6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013;

• 7.700% Fixed Series 1999C due March 1, 2032;

• Floating Rate Series 2001A due October 1, 2030;

• 5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011;

• Floating Rate Series 2001D due May 1, 2033;

• Floating Rate Taxable Series 2001I due December 1, 2036;

• Floating Rate Series 2002A due May 1, 2037;

• 6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013;

• 6.300% Fixed Series 2003B due July 1, 2032;

• 6.750% Fixed Series 2003C due October 1, 2038;

• 5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014;

• 5.000% Fixed Series 2006 due March 1, 2041;

Pollution Control Revenue Bonds—Sabine River Authority of Texas:

• 6.450% Fixed Series 2000A due June 1, 2021;

• 5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011;

• 5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011;

• 5.200% Fixed Series 2001C due May 1, 2028;

• 5.800% Fixed Series 2003A due July 1, 2022;

• 6.150% Fixed Series 2003B due August 1, 2022;

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Pollution Control Revenue Bonds—Trinity River Authority of Texas:

• 6.250% Fixed Series 2000A due May 1, 2028;

in each case to the extent outstanding on the Closing Date.

“Existing Notes Indentures” means each of the indentures or other documents containing the terms of the Existing Notes.

“Expenses Relating to a Unit Outage” means any expenses or other charges as a result of any outage or shut-down of any Unit, including any expenses or charges relating to (a) restarting any such Unit so that it may be placed back in service after such outage or shut-down, (b) purchases of power, natural gas or heat rate to meet commitments to sell, or offset a short position in, power, natural gas or heat rate that would otherwise have been met or offset from production generated by such Unit during the period of such outage or shut-down, net of the expenses not in fact incurred (including fuel and other operating expenses) that would have been incurred absent such an outage or shut down and (c) starting up, operating, maintaining and shutting down any other Unit that would not otherwise have been operating absent such outage or shut-down, including the fuel and other operating expenses to the extent in excess of the expenses not in fact incurred (including fuel and other operating costs) that would have been incurred absent such outage or shut down, incurred to start-up, operate, maintain and shut- down such Unit and that are required during the period of time that the shut-down or outaged Unit is out of service in order to meet the commitments of such shut-down or outaged Unit to sell, or offset a short position in, power, natural gas or heat rate.

“Fixed Charge Coverage Ratio” means, with respect to any Person for any period, the ratio of EBITDA of such Person for such period to the Fixed Charges of such Person for such period. In the event that the Issuer or any Restricted Subsidiary incurs, assumes, guarantees, redeems, retires or extinguishes any Indebtedness (other than Indebtedness incurred under any revolving credit facility unless such Indebtedness has been permanently repaid and has not been replaced) or issues or redeems Disqualified Stock or Preferred Stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated but prior to or simultaneously with the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Fixed Charge Coverage Ratio Calculation Date”), then the Fixed Charge Coverage Ratio shall be calculated giving pro forma effect to such incurrence, assumption, guarantee, redemption, retirement or extinguishment of Indebtedness, or such issuance or redemption of Disqualified Stock or Preferred Stock, as if the same had occurred at the beginning of the applicable four-quarter period.

For purposes of making the computation referred to above, Investments, acquisitions, dispositions, mergers, consolidations and disposed operations (as determined in accordance with GAAP) that have been made by the Issuer or any of its Restricted Subsidiaries during the four-quarter reference period or subsequent to such reference period and on or prior to or simultaneously with the Fixed Charge Coverage Ratio Calculation Date shall be calculated on a pro forma basis assuming that all such Investments, acquisitions, dispositions, mergers, consolidations and disposed operations (and the change in any associated fixed charge obligations and the change in EBITDA resulting therefrom) had occurred on the first day of the four-quarter reference period. If, since the beginning of such period, any Person that subsequently became a Restricted Subsidiary or was merged with or into the Issuer or any of its Restricted Subsidiaries since the beginning of such period shall have made any Investment, acquisition, disposition, merger, consolidation or disposed operation that would have required adjustment pursuant to this definition, then the Fixed Charge Coverage Ratio shall be calculated giving pro forma effect thereto for such period as if such Investment, acquisition, disposition, merger, consolidation or disposed operation had occurred at the beginning of the applicable four-quarter period.

For purposes of this definition, whenever pro forma effect is to be given to a transaction, the pro forma calculations shall be made in good faith by a responsible financial or accounting officer of the Issuer. If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest on such Indebtedness shall be calculated as if the rate in effect on the Fixed Charge Coverage Ratio Calculation Date had

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been the applicable rate for the entire period (taking into account any Hedging Obligations applicable to such Indebtedness). Interest on a Capitalized Lease Obligation shall be deemed to accrue at an interest rate reasonably determined by a responsible financial or accounting officer of the Issuer to be the rate of interest implicit in such Capitalized Lease Obligation in accordance with GAAP. For purposes of making the computation referred to above, interest on any Indebtedness under a revolving credit facility computed on a pro forma basis shall be computed based upon the average daily balance of such Indebtedness during the applicable period except as set forth in the first paragraph of this definition. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a eurocurrency interbank offered rate or other rate shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as the Issuer may designate.

“Fixed Charges” means, with respect to any Person for any period, the sum of:

(1) Consolidated Interest Expense of such Person for such period;

(2) all cash dividends or other distributions paid (excluding items eliminated in consolidation) on any series of Preferred Stock during such period; and

(3) all cash dividends or other distributions paid (excluding items eliminated in consolidation) on any series of Disqualified Stock during such period.

“Foreign Subsidiary” means, with respect to any Person, any Restricted Subsidiary of such Person that is not organized or existing under the laws of the United States, any state or territory thereof or the District of Columbia and any Restricted Subsidiary of such Foreign Subsidiary.

“GAAP” means generally accepted accounting principles in the United States which are in effect on the Closing Date.

“Government Authority” means any nation or government, any state, province, territory or other political subdivision thereof, and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government, including without limitation ERCOT.

“Government Securities” means securities that are:

(1) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged; or

(2) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the timely payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States of America,

which, in either case, are not callable or redeemable at the option of the issuers thereof, and shall also include a depository receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act), as custodian with respect to any such Government Securities or a specific payment of principal of or interest on any such Government Securities held by such custodian for the account of the holder of such depository receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the Government Securities or the specific payment of principal of or interest on the Government Securities evidenced by such depository receipt.

“guarantee” means a guarantee (other than by endorsement of negotiable instruments for collection in the ordinary course of business), direct or indirect, in any manner (including letters of credit and reimbursement agreements in respect thereof), of all or any part of any Indebtedness or other obligations.

“Guarantee” means the guarantee by any Guarantor of the Issuer’s Obligations under the Indenture.

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“Guarantor” means each Restricted Subsidiary that Guarantees the Notes in accordance with the terms of the Indenture.

“Hazardous Materials” means (a) any petroleum or petroleum products, radioactive materials, friable asbestos, urea formaldehyde foam insulation, transformers or other equipment that contain dielectric fluid containing regulated levels of polychlorinated biphenyls and radon gas; (b) any chemicals, materials or substances defined as or included in the definition of “hazardous substances,” “toxic substances,” “toxic pollutants,” “contaminants,” or “pollutants” or words of similar import, under any applicable Environmental Law; and (c) any other chemical, material or substance, which is prohibited, limited or regulated by any Environmental Law.

“Hedging Obligations” means with respect to any Person, the obligations of such Person under (a) any and all rate swap transactions, basis swaps, credit derivative transactions, forward rate transactions, commodity swaps, commodity options, forward commodity contracts, equity or equity index swaps or options, bond or bond price or bond index swaps or options or forward bond or forward bond price or forward bond index transactions, interest rate options, forward foreign exchange transactions, cap transactions, floor transactions, collar transactions, currency swap transactions, cross-currency rate swap transactions, currency options, spot contracts, or any other similar transactions or any combination of any of the foregoing (including any options to enter into any of the foregoing), whether or not any such transaction is governed by or subject to any master agreement, (b) any and all transactions of any kind, and the related confirmations, which are subject to the terms and conditions of, or governed by, any form of master agreement published by the International Swaps and Derivatives Association, Inc., any International Foreign Exchange Master Agreement or any other master agreement (any such master agreement, together with any related schedules, a “Master Agreement”), including any such obligations or liabilities under any Master Agreement and (c) physical or financial commodity contracts or agreements, power purchase or sale agreements, fuel purchase or sale agreements, environmental credit purchase or sale agreements, power transmission agreements, commodity transportation agreements, fuel storage agreements, netting agreements (including Netting Agreements), capacity agreement and commercial or trading agreements, each with respect to, or including the purchase, sale, exchange of (or the option to purchase, sell or exchange), transmission, transportation, storage, distribution, processing, sale, lease or hedge of, any Covered Commodity price or price indices for any such Covered Commodity or services or any other similar derivative agreements, and any other similar agreements.

“Holder” means the Person in whose name a Note is registered on the registrar’s books.

“Incremental Deposit L/C Loans” means Incremental Deposit L/C Loans under, and as defined in, the TCEH Senior Secured Facilities.

“Indebtedness” means, with respect to any Person, without duplication:

(1) any indebtedness (including principal and premium) of such Person, whether or not contingent:

(a) in respect of borrowed money;

(b) evidenced by bonds, notes, debentures or similar instruments or letters of credit or bankers’ acceptances (or, without duplication, reimbursement agreements in respect thereof);

(c) representing the balance deferred and unpaid of the purchase price of any property (including Capitalized Lease Obligations), except (i) any such balance that constitutes a trade payable or similar obligation to a trade creditor, in each case accrued in the ordinary course of business and (ii) any earn-out obligations until such obligation becomes a liability on the balance sheet of such Person in accordance with GAAP; or

(d) representing any Hedging Obligations;

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if and to the extent that any of the foregoing Indebtedness (other than letters of credit and Hedging Obligations) would appear as a liability upon a balance sheet (excluding the footnotes thereto) of such Person prepared in accordance with GAAP;

(2) to the extent not otherwise included, any obligation by such Person to be liable for, or to pay, as obligor, guarantor or otherwise on, the obligations of the type referred to in clause (1) of a third Person (whether or not such items would appear upon the balance sheet of the such obligor or guarantor), other than by endorsement of negotiable instruments for collection in the ordinary course of business; and

(3) to the extent not otherwise included, the obligations of the type referred to in clause (1) of a third Person secured by a Lien on any asset owned by such first Person, whether or not such Indebtedness is assumed by such first Person; provided that the amount of Indebtedness of such first Person for purposes of this clause (3) shall be deemed to be equal to the lesser of (i) the aggregate unpaid amount of such Indebtedness and (ii) the fair market value of the property encumbered thereby as determined by such first Person in good faith;

provided, however, that notwithstanding the foregoing, Indebtedness shall be deemed not to include (a) Contingent Obligations incurred in the ordinary course of business or (b) obligations under or in respect of Receivables Facilities or (c) amounts payable by and between the Issuer and its Subsidiaries in connection with retail clawback or other regulatory transition issues.

“Independent Financial Advisor” means an accounting, appraisal, investment banking firm or consultant to Persons engaged in Similar Businesses of nationally recognized standing that is, in the good faith judgment of the Issuer, qualified to perform the task for which it has been engaged.

“Initial Purchasers” means Morgan Stanley & Co. Incorporated, Goldman, Sachs & Co., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities Inc. and Lehman Brothers Inc.

“Investment Grade Rating” means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s and BBB- (or the equivalent) by S&P, or an equivalent rating by any other Rating Agency.

“Investment Grade Securities” means:

(1) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality thereof (other than Cash Equivalents);

(2) debt securities or debt instruments with an Investment Grade Rating, but excluding any debt securities or instruments constituting loans or advances among the Issuer and its Subsidiaries;

(3) investments in any fund that invests exclusively in investments of the type described in clauses (1) and (2) which fund may also hold immaterial amounts of cash pending investment or distribution; and

(4) corresponding instruments in countries other than the United States customarily utilized for high quality investments.

“Investments” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of loans (including guarantees), advances or capital contributions (excluding accounts receivable, trade credit, advances to customers, commissions, travel and similar advances to officers and employees, in each case made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities issued by any other Person and investments that are required by GAAP to be classified on the balance sheet (excluding the footnotes) of the Issuer in the same manner as the other investments included in this definition to the extent such transactions involve the transfer of cash or other property.

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For purposes of the definition of “Unrestricted Subsidiary” and the covenant described under “Certain Covenants—Limitation on Restricted Payments”:

(1) “Investments” shall include the portion (proportionate to the Issuer’s equity interest in such Subsidiary) of the fair market value of the net assets of a Subsidiary of the Issuer at the time that such Subsidiary is designated an Unrestricted Subsidiary; provided, however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the Issuer shall be deemed to continue to have a permanent “Investment” in an Unrestricted Subsidiary in an amount (if positive) equal to:

(a) the Issuer’s “Investment” in such Subsidiary at the time of such redesignation; less

(b) the portion (proportionate to the Issuer equity interest in such Subsidiary) of the fair market value of the net assets of such Subsidiary at the time of such redesignation; and

(2) any property transferred to or from an Unrestricted Subsidiary shall be valued at its fair market value at the time of such transfer, in each case as determined in good faith by the Issuer.

“Investors” means Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P., J.P. Morgan Ventures Corporation, Citigroup Global Markets Inc., Morgan Stanley & Co. Incorporated, Goldman, Sachs & Co. and LB I Group and each of their respective Affiliates but not including, however, any portfolio companies of any of the foregoing.

“Issue Date” means the first date on which any Notes are issued pursuant to the Indenture.

“Issuer” has the meaning set forth in the first paragraph under “General”; provided that when used in the context of determining the fair market value of an asset or liability under the Indenture, “Issuer” shall be deemed to mean the board of directors of the Issuer when the fair market value is equal to or in excess of $500.0 million (unless otherwise expressly stated).

“Legal Holiday” means a Saturday, a Sunday or a day on which commercial banking institutions are not required to be open in the State of New York.

“Lien” means, with respect to any asset, any mortgage, lien (statutory or otherwise), pledge, hypothecation, charge, security interest, preference, priority or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction; provided that in no event shall an operating lease be deemed to constitute a Lien.

“Moody’s” means Moody’s Investors Service, Inc. and any successor to its rating agency business.

“Necessary CapEx Debt” means Indebtedness of the Issuer or any of its Restricted Subsidiaries incurred for the purpose of financing Necessary Capital Expenditures.

“Necessary Capital Expenditures” means capital expenditures by the Issuer and its Restricted Subsidiaries that are required by applicable law (other than Environmental Law) or otherwise undertaken voluntarily for health and safety reasons (other than as required by Environmental Law). The term “Necessary Capital Expenditures” does not include any capital expenditure undertaken primarily to increase the efficiency of, expand or re-power any power generation facility.

“Net Income” means, with respect to any Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of Preferred Stock dividends.

“Net Proceeds” means the aggregate cash proceeds received by the Issuer or any of its Restricted Subsidiaries in respect of any Asset Sale (including a Casualty Event), including any cash received upon the sale

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or other disposition of any Designated Non-cash Consideration received in any Asset Sale (including a Casualty Event), net of the direct costs relating to such Asset Sale (including a Casualty Event) and the sale or disposition of such Designated Non-cash Consideration, including legal, accounting and investment banking fees, and brokerage and sales commissions, any relocation expenses incurred as a result thereof, taxes paid or payable as a result thereof (after taking into account any available tax credits or deductions and any tax sharing arrangements), amounts required to be applied to the repayment of principal, premium, if any, and interest on Senior Indebtedness required (other than required by clause (1) of the second paragraph of “Repurchase at the Option of Holders—Asset Sales”) to be paid as a result of such transaction and any deduction of appropriate amounts to be provided by the Issuer or any of its Restricted Subsidiaries as a reserve in accordance with GAAP against any liabilities associated with the asset disposed of in such transaction and retained by the Issuer or any of its Restricted Subsidiaries after such sale or other disposition thereof, including pension and other post-employment benefit liabilities and liabilities related to environmental matters or against any indemnification obligations associated with such transaction.

“Netting Agreement” shall mean a netting agreement, master netting agreement or other similar document having the same effect as a netting agreement or master netting agreement and, as applicable, any collateral annex, security agreement or other similar document related to any master netting agreement or Permitted Contract.

“Obligations” means any principal, interest (including any interest accruing subsequent to the filing of a petition in bankruptcy, reorganization or similar proceeding at the rate provided for in the documentation with respect thereto, whether or not such interest is an allowed claim under applicable state, federal or foreign law), premium, penalties, fees, indemnifications, reimbursements (including reimbursement obligations with respect to letters of credit and bankers’ acceptances), damages and other liabilities, and guarantees of payment of such principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities, payable under the documentation governing any Indebtedness.

“Officer” means the Chairman of the Board, the Chief Executive Officer, the President, any Executive Vice President, Senior Vice President or Vice President, the Treasurer or the Secretary of the Issuer.

“Officer’s Certificate” means a certificate signed on behalf of the Issuer by an Officer of the Issuer, who must be the principal executive officer, the principal financial officer, the treasurer or the principal accounting officer of the Issuer that meets the requirements set forth in the Indenture.

“Oncor Electric Delivery Facility” means the revolving credit agreement to be entered into as of the Closing Date by and among Oncor Electric Delivery, as borrower, the lenders party thereto in their capacities as lenders thereunder and JPMorgan Chase Bank, N.A., as Administrative Agent, including any guarantees, collateral documents, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications, extensions, renewals, restatements, refundings or refinancings thereof and any indentures or credit facilities or commercial paper facilities with banks or other institutional lenders or investors that replace, refund or refinance any part of the loans, notes, other credit facilities or commitments thereunder, including any such replacement, refunding or refinancing facility or indenture that increases the amount borrowable thereunder or alters the maturity thereof.

“Oncor Holdings” means Oncor Electric Delivery Holdings LLC.

“Oncor Subsidiaries” means the Subsidiaries of Energy Future Intermediate Holding, including Oncor Holdings and its Subsidiaries, all of which shall be Unrestricted Subsidiaries existing on the Issue Date.

“Opinion of Counsel” means a written opinion from legal counsel who is acceptable to the Trustee. The counsel may be an employee of or counsel to the Issuer or the Trustee.

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“Partial PIK Interest” has the meaning set forth under “Principal, Maturity and Interest—Toggle Notes.”

“Permitted Asset Swap” means the concurrent purchase and sale or exchange of Related Business Assets or a combination of Related Business Assets and cash or Cash Equivalents between the Issuer or any of its Restricted Subsidiaries and another Person; provided, that any cash or Cash Equivalents received must be applied in accordance with the covenant described under “Repurchase at the Option of Holders—Asset Sales.”

“Permitted Holders” means each of the Investors, members of management (including directors) of the Issuer or any of its Subsidiaries who on the Closing Date are (or will be at any time prior to the first anniversary of the Closing Date) holders of Equity Interests of the Issuer (or any of its direct or indirect parent companies) and any group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act or any successor provision) of which any of the foregoing are members; provided that, in the case of such group and without giving effect to the existence of such group or any other group, such Investors and members of management, collectively, have beneficial ownership of more than 50% of the total voting power of the Voting Stock of the Issuer or any of its direct or indirect parent companies.

“Permitted Investments” means:

(1) any Investment in the Issuer or any of its Restricted Subsidiaries;

(2) any Investment in cash and Cash Equivalents or Investment Grade Securities;

(3) any Investment by the Issuer or any of its Restricted Subsidiaries in a Person that is engaged in a Similar Business if as a result of such Investment:

(a) such Person becomes a Restricted Subsidiary; or

(b) such Person, in one transaction or a series of related transactions, is merged or consolidated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, the Issuer or a Restricted Subsidiary,

and, in each case, any Investment held by such Person; provided that such Investment was not acquired by such Person in contemplation of such acquisition, merger, consolidation or transfer;

(4) any Investment in securities or other assets not constituting cash, Cash Equivalents or Investment Grade Securities and received in connection with an Asset Sale made pursuant to the provisions described under “Repurchase at the Option of Holders—Asset Sales” or any other disposition of assets not constituting an Asset Sale;

(5) any Investment existing on the Closing Date;

(6) any Investment acquired by the Issuer or any of its Restricted Subsidiaries:

(a) in exchange for any other Investment or accounts receivable held by the Issuer or any such Restricted Subsidiary in connection with or as a result of a bankruptcy, workout, reorganization or recapitalization of the issuer of such other Investment or accounts receivable; or

(b) as a result of a foreclosure by the Issuer or any of its Restricted Subsidiaries with respect to any secured Investment or other transfer of title with respect to any secured Investment in default;

(7) Hedging Obligations permitted under clause (10) of the second paragraph of the covenant described in “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(8) any Investment in a Similar Business having an aggregate fair market value, taken together with all other Investments made pursuant to this clause (8) that are at that time outstanding, not to exceed 3.5% of Total Assets at the time of such Investment (with the fair market value of each Investment being measured at the time made and without giving effect to subsequent changes in value);

(9) Investments the payment for which consists of Equity Interests (exclusive of Disqualified Stock) of the Issuer or any of its direct or indirect parent companies; provided, however, that such Equity Interests

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will not increase the amount available for Restricted Payments under clause (3) of the first paragraph under the covenant described in “Certain Covenants—Limitations on Restricted Payments”;

(10) guarantees of Indebtedness of the Issuer or any of its Restricted Subsidiaries permitted under the covenant described under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(11) any transaction to the extent it constitutes an Investment that is permitted and made in accordance with the provisions of the second paragraph of the covenant described under “Certain Covenants—Transactions with Affiliates” (except transactions described in clauses (2), (5) and (9) of such paragraph);

(12) Investments consisting of purchases and acquisitions of inventory, fuel (including all forms of nuclear fuel), supplies, material or equipment;

(13) additional Investments having an aggregate fair market value, taken together with all other Investments made pursuant to this clause (13) that are at that time outstanding (without giving effect to the sale of an Investment to the extent the proceeds of such sale do not consist of cash or marketable securities), not to exceed 3.5% of Total Assets at the time of such Investment (with the fair market value of each Investment being measured at the time made and without giving effect to subsequent changes in value);

(14) Investments relating to a Receivables Subsidiary that, in the good faith determination of the Issuer, are necessary or advisable to effect any Receivables Facility for the benefit of the Issuer or any of its Restricted Subsidiaries;

(15) advances to, or guarantees of Indebtedness of, employees not in excess of $25.0 million outstanding at any one time, in the aggregate;

(16) loans and advances to officers, directors and employees for business-related travel expenses, moving expenses and other similar expenses, in each case incurred in the ordinary course of business or consistent with past practices or to fund such Person’s purchase of Equity Interests of the Issuer or any direct or indirect parent company thereof;

(17) any Investment in any Subsidiary or any joint venture in connection with intercompany cash management arrangements or related activities arising in the ordinary course of business;

(18) any Investment in Shell Wind in an aggregate amount not to exceed $1,500.0 million; and

(19) one or more letters of credit in an aggregate amount not to exceed $170.0 million posted by a Restricted Subsidiary in favor of an Oncor Subsidiary to secure that Restricted Subsidiary’s contractual obligations to that Oncor Subsidiary.

“Permitted Liens” means, with respect to any Person:

(1) pledges or deposits by such Person under workmen’s compensation laws, unemployment insurance laws or similar legislation, or good faith deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits to secure public or statutory obligations of such Person or deposits of cash or U.S. government bonds to secure surety or appeal bonds to which such Person is a party, or deposits as security for contested taxes or import duties or for the payment of rent, in each case incurred in the ordinary course of business (including in connection with the construction or restoration of facilities for the generation, transmission or distribution of electricity) or otherwise constituting Permitted Investments;

(2) Liens imposed by law, such as carriers’, warehousemen’s and mechanics’ Liens, in each case for sums not yet overdue for a period of more than 30 days or being contested in good faith by appropriate proceedings or other Liens arising out of judgments or awards against such Person with respect to which such Person shall then be proceeding with an appeal or other proceedings for review if adequate reserves with respect thereto are maintained on the books of such Person in accordance with GAAP;

(3) Liens for taxes, assessments or other governmental charges not yet overdue for a period of more than 30 days or payable or subject to penalties for nonpayment or which are being contested in good faith by

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appropriate proceedings diligently conducted, if adequate reserves with respect thereto are maintained on the books of such Person in accordance with GAAP;

(4) Liens in favor of issuers of performance and surety bonds or bid bonds or with respect to other regulatory requirements or letters of credit issued pursuant to the request of and for the account of such Person in the ordinary course of its business;

(5) minor survey or title exceptions or irregularities, minor encumbrances, easements or reservations of, or rights of others for, licenses, permits, conditions, covenants, rights-of-way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning or other restrictions as to the use of real properties or Liens incidental to the conduct of the business of such Person or to the ownership of its properties which were not incurred in connection with Indebtedness and which do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;

(6) Liens securing Indebtedness permitted to be incurred pursuant to clause (4), (12) or (13) of the second paragraph under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”; provided that (a) Liens securing Indebtedness, Disqualified Stock or Preferred Stock permitted to be incurred pursuant to clause (13) relate only to Refinancing Indebtedness that serves to refund or refinance Indebtedness, Disqualified Stock or Preferred Stock incurred under clause (4) or (12) of the second paragraph under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock,” and (b) Liens securing Indebtedness, Disqualified Stock or Preferred Stock permitted to be incurred pursuant to clause (4) of the second paragraph under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” extend only to the assets so financed, purchased, constructed or improved;

(7) Liens existing on the Closing Date (other than Liens in favor of the lenders under the TCEH Senior Secured Facilities);

(8) Liens on property or shares of stock of a Person at the time such Person becomes a Subsidiary; provided, however, such Liens are not created or incurred in connection with, or in contemplation of, such other Person becoming such a Subsidiary; provided, further, however, that such Liens may not extend to any other property owned by the Issuer or any of its Restricted Subsidiaries;

(9) Liens on property at the time the Issuer or a Restricted Subsidiary acquired the property, including any acquisition by means of a merger or consolidation with or into the Issuer or any of its Restricted Subsidiaries; provided, however, that such Liens are not created or incurred in connection with, or in contemplation of, such acquisition; provided, further, however, that the Liens may not extend to any other property owned by the Issuer or any of its Restricted Subsidiaries;

(10) Liens securing Indebtedness or other obligations of a Restricted Subsidiary owing to the Issuer or another Restricted Subsidiary permitted to be incurred in accordance with the covenant described under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(11) Liens securing Hedging Obligations, of the Issuer or its Restricted Subsidiaries incurred under clause (10) of the second paragraph under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”; provided that such agreements were entered into in the ordinary course of business and not for speculative purposes (as determined by the Issuer in its reasonable discretion acting in good faith) and, in the case of any commodity Hedging Obligations or any Hedging Obligation of the type described in clause (c) of the definition of “Hedging Obligations,” entered into in order to hedge against or manage fluctuations in the price or availability of any Covered Commodity;

(12) Liens on specific items of inventory or other goods and proceeds of any Person securing such Person’s obligations in respect of bankers’ acceptances issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

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(13) leases, subleases, licenses or sublicenses granted to others in the ordinary course of business which do not materially interfere with the ordinary conduct of the business of the Issuer or any of its Restricted Subsidiaries;

(14) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Issuer and its Restricted Subsidiaries in the ordinary course of business;

(15) Liens in favor of the Issuer or any Guarantor;

(16) [Intentionally omitted];

(17) Liens on accounts receivable, other Receivables Facility assets, or accounts into which collections or proceeds of Receivables Facility assets are deposited, in each case in connection with a Receivables Facility for the benefit of the Issuer or its Restricted Subsidiaries;

(18) Liens to secure any refinancing, refunding, extension, renewal or replacement (or successive refinancing, refunding, extensions, renewals or replacements) as a whole, or in part, of any Indebtedness secured by any Lien referred to in the foregoing clauses (6), (7), (8) and (9); provided, however, that (a) such new Lien shall be limited to all or part of the same property that secured the original Lien (plus improvements on such property), and (b) the Indebtedness secured by such Lien at such time is not increased to any amount greater than the sum of (i) the outstanding principal amount or, if greater, committed amount of the Indebtedness described under clauses (6), (7), (8), and (9) at the time the original Lien became a Permitted Lien under the Indenture, and (ii) an amount necessary to pay any fees and expenses, including premiums, related to such refinancing, refunding, extension, renewal or replacement;

(19) deposits made in the ordinary course of business to secure liability to insurance carriers;

(20) other Liens securing obligations incurred in the ordinary course of business which obligations do not exceed $100.0 million at any one time outstanding;

(21) Liens securing judgments for the payment of money not constituting an Event of Default under clause (5) under the caption “Events of Default and Remedies” so long as such Liens are adequately bonded and any appropriate legal proceedings that may have been duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired;

(22) Liens in favor of customs and revenue authorities arising as a matter of law to secure payment of customs duties in connection with the importation of goods in the ordinary course of business;

(23) Liens (i) of a collection bank arising under Section 4-210 of the Uniform Commercial Code, or any comparable or successor provision, on items in the course of collection, and (ii) in favor of banking institutions arising as a matter of law encumbering deposits (including the right of set-off) and which are within the general parameters customary in the banking industry;

(24) Liens deemed to exist in connection with Investments in repurchase agreements permitted by the covenant described under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”; provided that such Liens do not extend to any assets other than those that are the subject of such repurchase agreements;

(25) ground leases or subleases, licenses or sublicenses in respect of real property on which facilities owned or leased by the Issuer or any of its Subsidiaries are located;

(26) Liens that are contractual rights of set-off (i) relating to the establishment of depository relations with banks not given in connection with the issuance of Indebtedness, (ii) relating to pooled deposit or sweep accounts of the Issuer or any of its Restricted Subsidiaries to permit satisfaction of overdraft or similar obligations incurred in the ordinary course of business of the Issuer and its Restricted Subsidiaries or (iii) relating to purchase orders and other agreements entered into with customers of the Issuer or any of its Restricted Subsidiaries in the ordinary course of business;

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(27) Liens arising out of conditional sale, title retention, consignment or similar arrangements for the sale or purchase of goods entered into by the Issuer or any Restricted Subsidiary in the ordinary course of business;

(28) rights reserved to or vested in others to take or receive any part of, or royalties related to, the power, gas, oil, coal, lignite or other minerals or timber generated, developed, manufactured or produced by, or grown on, or acquired with, any property of the Issuer or any of its Restricted Subsidiaries and Liens upon the production from property of power, gas, oil, coal, lignite or other minerals or timber, and the by-products and proceeds thereof, to secure the obligations to pay all or a part of the expenses of exploration, drilling, mining or development of such property only out of such production or proceeds;

(29) Liens arising out of all presently existing and future division and transfer orders, advance payment agreements, processing contracts, gas processing plant agreements, operating agreements, gas balancing or deferred production agreements, pooling, unitization or communitization agreements, pipeline, gathering or transportation agreements, platform agreements, drilling contracts, injection or repressuring agreements, cycling agreements, construction agreements, salt water or other disposal agreements, leases or rental agreements, farm-out and farm-in agreements, exploration and development agreements, and any and all other contracts or agreements covering, arising out of, used or useful in connection with or pertaining to the exploration, development, operation, production, sale, use, purchase, exchange, storage, separation, dehydration, treatment, compression, gathering, transportation, processing, improvement, marketing, disposal or handling of any property of the Issuer or any of its Restricted Subsidiaries, provided that such agreements are entered into in the ordinary course of business (including in respect of construction and restoration activities);

(30) any restrictions on any stock or stock equivalents or other joint venture interests of the Issuer or any of its Restricted Subsidiaries providing for a breach, termination or default under any owners, participation, shared facility, joint venture, stockholder, membership, limited liability company or partnership agreement between such Person and one or more other holders of such stock or stock equivalents or interest of such Person, if a security interest or other Lien is created on such stock or stock equivalents or interest as a result thereof and other similar Liens;

(31) [Intentionally omitted];

(32) Liens and other exceptions to title, in either case on or in respect of any facilities of the Issuer or any of its Restricted Subsidiaries, arising as a result of any shared facility agreement entered into with respect to such facility, except to the extent that any such Liens or exceptions, individually or in the aggregate, materially adversely affect the value of the relevant property or materially impair the use of the relevant property in the operation of business of the Issuer or any of its Restricted Subsidiaries, taken as a whole;

(33) Liens on cash and Cash Equivalents (i) deposited by the Issuer or any of its Restricted Subsidiaries in margin accounts with or on behalf of brokers, credit clearing organizations, independent system operators, regional transmission organizations, pipelines, state agencies, federal agencies, futures contract brokers, customers, trading counterparties, or any other parties or issuers of surety bonds or (ii) pledged or deposited as collateral by the Issuer or any of its Restricted Subsidiaries with any of the entities described in clause (i) above to secure their respective obligations, in the case of each of clauses (i) and (ii) above, with respect to: (A) any contracts and transactions for the purchase, sale, exchange of, or the option (whether physical or financial) to purchase, sell or exchange (1) natural gas, (2) electricity, (3) coal and lignite, (4) petroleum-based liquids, (5) oil, (6) nuclear fuel (including enrichment and conversion), (7) emissions or other environmental credits, (8) waste byproducts, (9) weather, (10) power and other generation capacity, (11) heat rate, (12) congestion, (13) renewal energy credit, or (14) any other energy-related commodity or services or derivative (including ancillary services and related risk (such as location basis); (B) any contracts or transactions for the purchase, processing, transmission, transportation, distribution, sale, lease, hedge or storage of, or any other services related to any commodity or service identified in subparts (1)—(14) above, including any capacity agreement; (C) any financial derivative agreement (including but not

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limited to swaps, options or swaptions) related to any commodity identified in subparts (1)—(14) above, or to any interest rate or currency rate management activities; (D) any agreement for membership or participation in an organization that facilitates or permits the entering into or clearing of any netting agreement or any agreement described in this clause (33); (E) any agreement combining part or all of a netting agreement or part or all of any of the agreements described in this clause (33); (E) any document relating to any agreement described in this clause (33) that is filed with a Government Authority and any related service agreements; or (F) any commercial or trading agreements, each with respect to, or involving the purchase, transmission, distribution, sale, lease or hedge of, any energy, generation capacity or fuel, or any other energy related commodity or service, price or price indices for any such commodities or services or any other similar derivative agreements, and any other similar agreements (such agreements described in clauses (A) through (F) of this clause (33) being collectively, “Permitted Contracts”), Netting Agreements, Hedging Obligations and letters of credit supporting Permitted Contracts, Netting Agreements and Hedging Obligations;

(34) Liens arising under Section 9.343 of the Texas Uniform Commercial Code or similar statutes of states other than Texas;

(35) Liens created in the ordinary course of business in favor of banks and other financial institutions over credit balances of any bank accounts of the Issuer and its Subsidiaries held at such banks or financial institutions, as the case may be, to facilitate the operation of cash pooling and/or interest set-off arrangements in respect of such bank accounts in the ordinary course of business;

(36) any zoning, land use, environmental or similar law or right reserved to or vested in any Government Authority to control or regulate the use of any real property that does not materially interfere with the ordinary conduct of the business of the Issuer or any of its Restricted Subsidiaries, taken as a whole;

(37) any Lien arising by reason of deposits with or giving of any form of security to any Government Authority for any purpose at any time as required by applicable law as a condition to the transaction of any business or the exercise of any privilege or license, or to enable the Issuer or any of its Restricted Subsidiaries to maintain self-insurance or to participate in any fund for liability on any insurance risks;

(38) Liens, restrictions, regulations, easements, exceptions or reservations of any Government Authority applying particularly to nuclear fuel;

(39) rights reserved to or vested in any Government Authority by the terms of any right, power, franchise, grant, license or permit, or by any provision of applicable law, to terminate or modify such right, power, franchise, grant, license or permit or to purchase or recapture or to designate a purchaser of any of the property of such person;

(40) Liens arising under any obligations or duties affecting any of the property of the Issuer or any of its Restricted Subsidiaries to any Government Authority with respect to any franchise, grant, license or permit which do not materially impair the use of such property for the purposes for which it is held;

(41) rights reserved to or vested in any Government Authority to use, control or regulate any property of such person;

(42) any obligations or duties, affecting the property of the Issuer or any of its Restricted Subsidiaries, to any Government Authority with respect to any franchise, grant, license or permit;

(43) a set-off or netting rights granted by the Issuer or any Subsidiary of the Issuer pursuant to any agreements related to Hedging Obligations, Netting Agreements or Permitted Contracts solely in respect of amounts owing under such agreements;

(44) Liens (i) on cash advances in favor of the seller of any property to be acquired in an Investment described under the definition of “Permitted Investments” to be applied against the purchase price for such Investment and (ii) consisting of an agreement to sell, transfer, lease or otherwise dispose of any property in

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a transaction excluded from the definition described under “Asset Sale,” in each case, solely to the extent such Investment or sale, disposition, transfer or lease, as the case may be, would have been permitted on the date of the creation of such Lien;

(45) rights of first refusal and purchase options in favor of Aluminum Company of America (“Alcoa”) to purchase Sandow Unit 4 and/or the real property related thereto, as described in (i) the Sandow Unit 4 Agreement dated August 13, 1976, as amended, between Alcoa and Texas Power & Light Company (“TPL”) and (ii) Deeds dated March 14, 1978 and July 21, 1980, as amended, executed by Alcoa conveying to TPL the Sandow Four real property; and

(46) any amounts held by a trustee in the funds and accounts under any indenture securing any revenue bonds issued for the benefit of the Issuer or any of its Restricted Subsidiaries.

For purposes of this definition, the term “Indebtedness” shall be deemed to include interest on such Indebtedness.

“Person” means any individual, corporation, limited liability company, partnership, joint venture, association, joint stock company, trust, unincorporated organization, government or any agency or political subdivision thereof or any other entity.

“PIK Interest” has the meaning set forth under “Principal, Maturity and Interest—Toggle Notes.”

“PIK Notes” has the meaning set forth under “Principal, Maturity and Interest—Toggle Notes.”

“PIK Payment” has the meaning set forth under “Principal, Maturity and Interest—Toggle Notes.”

“Preferred Stock” means any Equity Interest with preferential rights of payment of dividends or upon liquidation, dissolution or winding up.

“Purchase Money Obligations” means any Indebtedness incurred to finance or refinance the acquisition, leasing, construction, repair, restoration, replacement, expansion or improvement of property (real or personal) or assets (other than Capital Stock), and whether acquired through the direct acquisition of such property or assets, or otherwise, incurred in respect of capital expenditures, including Environmental CapEx Debt and Necessary CapEx Debt.

“Qualified Proceeds” means assets that are used or useful in, or Capital Stock of any Person engaged in, a Similar Business; provided that the fair market value of any such assets or Capital Stock shall be determined by the Issuer in good faith.

“Rating Agencies” means Moody’s and S&P or if Moody’s or S&P or both shall not make a rating on the applicable Notes or other investment publicly available, a nationally recognized statistical rating agency or agencies, as the case may be, selected by the Issuer which shall be substituted for Moody’s or S&P or both, as the case may be.

“Receivables Facility” means any of one or more receivables financing facilities or programs as amended, supplemented, modified, extended, renewed, restated or refunded from time to time, the Obligations of which are non-recourse (except for customary representations, warranties, covenants and indemnities made in connection with such facilities) to the Issuer or any of its Restricted Subsidiaries (other than a Receivables Subsidiary) pursuant to which the Issuer or any of its Restricted Subsidiaries purports to sell its accounts receivable to either (a) a Person that is not a Restricted Subsidiary or (b) a Receivables Subsidiary that in turn funds such purchase by purporting to sell its accounts receivable to a Person that is not a Restricted Subsidiary or by borrowing from such a Person or from another Receivables Subsidiary that in turn funds itself by borrowing from such a Person.

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“Receivables Fees” means distributions or payments made directly or by means of discounts with respect to any accounts receivable or participation interest therein issued or sold in connection with, and other fees paid to a Person that is not a Restricted Subsidiary in connection with any Receivables Facility.

“Receivables Subsidiary” means any Subsidiary formed for the purpose of facilitating or entering into one or more Receivables Facilities, and in each case engages only in activities reasonably related or incidental thereto.

“Redemption Date” has the meaning set forth under “Optional Redemption.”

“Registration Rights Agreement” means (1) the Registration Rights Agreement related to the Notes, dated as of the Issue Date, among the Issuer, the Guarantors and the Initial Purchasers, and (2) with respect to any Additional Notes, any registration rights agreement among the Issuer and the other parties thereto relating to the registration by the Issuer of such Additional Notes under the Securities Act.

“Related Business Assets” means assets (other than cash or Cash Equivalents) used or useful in a Similar Business; provided that any assets received by the Issuer or a Restricted Subsidiary in exchange for assets transferred by the Issuer or a Restricted Subsidiary will not be deemed to be Related Business Assets if they consist of securities of a Person, unless upon receipt of the securities of such Person, such Person would become a Restricted Subsidiary.

“Restoration Certificate” “ shall mean, with respect to any Casualty Event, an Officer’s Certificate provided to the Trustee prior to the 365^th day after such Casualty Event has occurred certifying (a) that the Issuer or such Restricted Subsidiary intends to use the proceeds received in connection with such Casualty Event to repair, restore or replace the property or assets in respect of which such Casualty Event occurred, (b) the approximate costs of completion of such repair, restoration or replacement and (c) that such repair, restoration or replacement will be completed within the later of (x) 450 days after the date on which cash proceeds with respect to such Casualty Event were received and (y) 180 days after delivery of such Restoration Certificate.

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Payment Coverage Ratio” means (i) for Restricted Payments (other than payments of cash dividends or distributions on, or in respect of, the Issuer’s Capital Stock, purchases for cash or other acquisitions for cash of any Capital Stock of the Issuer or any direct or indirect parent of the Issuer for the purpose of paying any such dividend or distribution to, or acquisitions of Capital Stock of any direct or indirect parent of the Issuer for cash from, the Investors, or guaranteeing any Indebtedness of any Affiliate of the Issuer for the purpose of paying such dividend, making such distribution or so acquiring such Capital Stock to or from the Investors, all such Restricted Payments being referred to as “Investor Payments”), the Fixed Charge Coverage Ratio of the Issuer and its Restricted Subsidiaries treating the Oncor Subsidiaries as Restricted Subsidiaries for purposes of such calculation and (ii) for Restricted Payments constituting Investor Payments, the Fixed Charge Coverage Ratio of the Issuer and its Restricted Subsidiaries.

“Restricted Subsidiary” means, at any time, any direct or indirect Subsidiary of the Issuer (including any Foreign Subsidiary) that is not then an Unrestricted Subsidiary; provided, however, that upon an Unrestricted Subsidiary’s ceasing to be an Unrestricted Subsidiary, such Subsidiary shall be included in the definition of “Restricted Subsidiary.”

“S&P” means Standard & Poor’s, a division of The McGraw-Hill Companies, Inc., and any successor to its rating agency business.

“Sale and Lease-Back Transaction” means any arrangement providing for the leasing by the Issuer or any of its Restricted Subsidiaries of any real or tangible personal property, which property has been or is to be sold or transferred by the Issuer or such Restricted Subsidiary to a third Person in contemplation of such leasing.

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“SEC” means the U.S. Securities and Exchange Commission.

“Secured Indebtedness” means any Indebtedness of the Issuer or any of its Restricted Subsidiaries secured by a Lien.

“Securities Act” means the Securities Act of 1933, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Senior Indebtedness” means:

(1) all Indebtedness of the Issuer or any Guarantor outstanding under the TCEH Senior Secured Facilities, the TCEH Notes and related guarantees, the TCEH Senior Interim Facility and related guarantees or the Notes and related Guarantees (including interest accruing on or after the filing of any petition in bankruptcy or similar proceeding or for reorganization of the Issuer or any Guarantor (at the rate provided for in the documentation with respect thereto, regardless of whether or not a claim for post-filing interest is allowed in such proceedings)), and any and all other fees, expense reimbursement obligations, indemnification amounts, penalties, and other amounts (whether existing on the Closing Date or thereafter created or incurred) and all obligations of the Issuer or any Guarantor to reimburse any bank or other Person in respect of amounts paid under letters of credit, acceptances or other similar instruments;

(2) all Hedging Obligations (and guarantees thereof) owing to a Lender (as defined in the TCEH Senior Secured Facilities) or any Affiliate of such Lender (or any Person that was a Lender or an Affiliate of such Lender at the time the applicable agreement giving rise to such Hedging Obligation was entered into); provided that such Hedging Obligations are permitted to be incurred under the terms of the Indenture;

(3) any other Indebtedness of the Issuer or any Guarantor permitted to be incurred under the terms of the Indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is subordinated in right of payment to the Notes or any related Guarantee; and

(4) all Obligations with respect to the items listed in the preceding clauses (1), (2) and (3);

provided, however, that Senior Indebtedness shall not include:

(a) any obligation of such Person to the Issuer or any of its Subsidiaries;

(b) any liability for federal, state, local or other taxes owed or owing by such Person;

(c) any accounts payable or other liability to trade creditors arising in the ordinary course of business;

(d) any Indebtedness or other Obligation of such Person which is subordinate or junior in any respect to any other Indebtedness or other Obligation of such Person;

(e) that portion of any Indebtedness which at the time of incurrence is incurred in violation of the Indenture;

(f) Energy Future Competitive Holdings Floating Rate Junior Subordinated Debentures, Series D due 2037; or

(g) Energy Future Competitive Holdings 8.175% Fixed Junior Subordinated Debentures, Series E due 2037.

“Shell Wind” means a joint venture with Shell WindEnergy Inc. (or a similar entity) in which the Issuer and its Restricted Subsidiaries have up to a 50% ownership interest relating to the joint development of a 3,000 megawatt wind project in Texas and other renewable energy projects in Texas.

“Significant Subsidiary” means any Restricted Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such regulation is in effect on the Closing Date.

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“Similar Business” means any business conducted or proposed to be conducted by the Issuer and its Subsidiaries on the Closing Date or any business that is similar, reasonably related, incidental or ancillary thereto.

“Sponsor Management Agreement” means the management agreement between certain of the management companies associated with the Investors and the Issuer.

“Subordinated Indebtedness” means,

(1) any Indebtedness of the Issuer which is by its terms subordinated in right of payment to the Notes, and

(2) any Indebtedness of any Guarantor which is by its terms subordinated in right of payment to the Guarantee of such entity of the Notes.

“Subsidiary” means, with respect to any Person:

(1) any corporation, association, or other business entity (other than a partnership, joint venture, limited liability company or similar entity) of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof is at the time of determination owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof; and

(2) any partnership, joint venture, limited liability company or similar entity of which

(x) more than 50% of the capital accounts, distribution rights, total equity and voting interests or general or limited partnership interests, as applicable, are owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof whether in the form of membership, general, special or limited partnership or otherwise, and

(y) such Person or any Restricted Subsidiary of such Person is a controlling general partner or otherwise controls such entity.

“TCEH” means Texas Competitive Electric Holdings Company LLC.

“TCEH Senior Interim Facility” means the interim loan agreement, dated as of the Closing Date by and among Energy Future Competitive Holdings, as guarantor, TCEH, as borrower, the other guarantors parties thereto, the lenders party thereto in their capacities as lenders thereunder and Morgan Stanley Senior Funding, Inc., as Administrative Agent, including any guarantees, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications or restatements thereof.

“TCEH Senior Secured Facilities” means the credit agreement dated as of the Closing Date by and among Energy Future Competitive Holdings, as guarantor, TCEH, as borrower, the lenders party thereto in their capacities as lenders thereunder and Citibank, N.A., as Administrative Agent, including any guarantees, collateral documents, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications, extensions, renewals, restatements, refundings or refinancings thereof and any indentures or credit facilities or commercial paper facilities with banks or other institutional lenders or investors that replace, refund or refinance any part of the loans, notes, other credit facilities or commitments thereunder, including any such replacement, refunding or refinancing facility or indenture that increases the amount borrowable thereunder or alters the maturity thereof (provided that such increase in borrowings is permitted under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” above).

“TCEH Notes” means the notes issued by TCEH to refinance outstanding indebtedness under the TCEH Senior Interim Facility.

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“Total Assets” means the total assets of the Issuer and its Restricted Subsidiaries on a consolidated basis, as shown on the most recent consolidated balance sheet of the Issuer or such other Person as may be expressly stated.

“Transactions” means the transactions contemplated by the Transaction Agreement, borrowings under the TCEH Senior Secured Facilities, the EFH Senior Interim Facility, the TCEH Senior Interim Facility, the Oncor Electric Delivery Facility and any Receivables Facility as in effect on the Closing Date and any repayments of indebtedness of the Issuer and its Restricted Subsidiaries in connection therewith.

“Transaction Agreement” means the Agreement and Plan of Merger, dated as of February 25, 2007, among Merger Sub, Texas Energy Future Holdings Limited Partnership and TXU Corp.

“Treasury Rate” means, as of any Redemption Date, the yield to maturity as of such Redemption Date of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two Business Days prior to the Redemption Date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the Redemption Date to November 1, 2012; provided, however, that if the period from the Redemption Date to November 1, 2012 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year will be used.

“Trust Indenture Act” means the Trust Indenture Act of 1939, as amended (15 U.S.C. §§ 77aaa-77bbbb).

“Unit” shall mean an individual power plant generation system comprised of all necessary physically connected generators, reactors, boilers, combustion turbines and other prime movers operated together to independently generate electricity.

“Unrestricted Cash” means, as of any date, without duplication, (a) all cash and Cash Equivalents (in each case, free and clear of all Liens, other than nonconsensual Liens permitted by the covenant described under “Certain Covenants—Liens” and Liens permitted by clause (23), subclauses (i) and (ii) of clause (26) and clause (33) of the definition of Permitted Liens, included in the cash and cash equivalents accounts listed on the consolidated balance sheet of the Issuer and its Restricted Subsidiaries as of such date and (b) all unrestricted margin deposits related to commodity positions listed on the consolidated balance sheet of Issuer and the Restricted Subsidiaries.

“Unrestricted Subsidiary” means:

(1) each of the Oncor Subsidiaries;

(2) any Subsidiary of the Issuer which at the time of determination is an Unrestricted Subsidiary (as designated by the Issuer, as provided below); and

(3) any Subsidiary of an Unrestricted Subsidiary.

The Issuer may designate any Subsidiary of the Issuer (including any existing Subsidiary and any newly acquired or newly formed Subsidiary) to be an Unrestricted Subsidiary unless such Subsidiary or any of its Subsidiaries owns any Equity Interests or Indebtedness of, or owns or holds any Lien on, any property of, the Issuer or any Subsidiary of the Issuer (other than solely any Subsidiary of the Subsidiary to be so designated); provided that

(1) any Unrestricted Subsidiary must be an entity of which the Equity Interests entitled to cast at least a majority of the votes that may be cast by all Equity Interests having ordinary voting power for the election of directors or Persons performing a similar function are owned, directly or indirectly, by the Issuer;

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(2) such designation complies with the covenants described under “Certain Covenants—Limitation on Restricted Payments”; and

(3) each of:

(a) the Subsidiary to be so designated; and

(b) its Subsidiaries

has not at the time of designation, and does not thereafter, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable with respect to any Indebtedness pursuant to which the lender has recourse to any of the assets of the Issuer or any Restricted Subsidiary.

The Issuer may designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that, immediately after giving effect to such designation, no Default shall have occurred and be continuing and either:

(1) in the case of any Subsidiary of the Issuer other than TCEH and any of its Subsidiaries, (A) the Issuer could incur at least $1.00 of additional Indebtedness pursuant to clause (i) of the Fixed Charge Coverage Ratio test described in the first paragraph under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”; or (B) the Fixed Charge Coverage Ratio for the Issuer and its Restricted Subsidiaries would be greater than such ratio for the Issuer and its Restricted Subsidiaries immediately prior to such designation, in each case on a pro forma basis taking into account such designation; or

(2) in the case of TCEH and any of its Subsidiaries, (A) TCEH could Incur at least $1.00 of additional Indebtedness pursuant to clause (ii) of such Fixed Charge Coverage Ratio test or (B) such Fixed Charge Coverage Ratio for TCEH and its Restricted Subsidiaries would be greater than such ratio for TCEH and its Restricted Subsidiaries immediately prior to such designation, in each case on a pro forma basis taking into account such designation.

Any such designation by the Issuer shall be notified by the Issuer to the Trustee by promptly filing with the Trustee a copy of the resolution of the board of directors of the Issuer or any committee thereof giving effect to such designation and an Officer’s Certificate certifying that such designation complied with the foregoing provisions.

“Voting Stock” of any Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the board of directors of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness, Disqualified Stock or Preferred Stock, as the case may be, at any date, the quotient obtained by dividing:

(1) the sum of the products of the number of years from the date of determination to the date of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Disqualified Stock or Preferred Stock multiplied by the amount of such payment; by

(2) the sum of all such payments.

“Wholly-Owned Subsidiary” of any Person means a Subsidiary of such Person, 100% of the outstanding Equity Interests of which (other than directors’ qualifying shares) shall at the time be owned by such Person or by one or more Wholly-Owned Subsidiaries of such Person.

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CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES

Exchange Offers

The exchange of outstanding notes for exchange notes in the exchange offers will not constitute a taxable event to holders for U.S. federal income tax purposes. Consequently, you will not recognize gain or loss upon receipt of an exchange note, the holding period of the exchange note will include the holding period of the outstanding note exchanged therefor and the basis of the exchange note will be the same as the basis of the outstanding note immediately before the exchange.

In any event, persons considering the exchange of outstanding notes for exchange notes should consult their own tax advisors concerning the U.S. federal income tax consequences in light of their particular situations as well as any consequences arising under the laws of any other taxing jurisdiction.

Ownership of the Notes

The following is a summary of certain U.S. federal income and, in the case of non-U.S. holders (as defined below), estate tax consequences of the purchase, ownership and disposition of the notes as of the date of this prospectus. Unless otherwise stated, this summary deals only with notes held as capital assets (generally, property held for investment).

As used herein, a “U.S. holder” means a beneficial owner of the notes that is for U.S. federal income tax purposes any of the following:

• an individual citizen or resident of the United States;

• a corporation (or any other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

• an estate the income of which is subject to U.S. federal income taxation regardless of its source; or

• a trust if it (1) is subject to the primary supervision of a court within the United States and one or more United States persons have the authority to control all substantial decisions of the trust or (2) has a valid election in effect under applicable United States Treasury regulations to be treated as a United States person.

The term “non-U.S. holder” means a beneficial owner of the notes (other than a partnership or any other entity treated as a partnership for U.S. federal income tax purposes) that is not a U.S. holder.

This summary does not represent a detailed description of the U.S. federal income tax consequences applicable to you if you are a person subject to special tax treatment under the U.S. federal income tax laws, including, without limitation:

• a dealer in securities or currencies;

• a financial institution;

• a regulated investment company;

• a real estate investment trust;

• a tax-exempt organization;

• an insurance company;

• a person holding the notes as part of a hedging, integrated, conversion or constructive sale transaction or a straddle;

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• a trader in securities that has elected the mark-to-market method of accounting for your securities;

• a person liable for alternative minimum tax;

• a partnership or other pass-through entity for U.S. federal income tax purposes;

• a U.S. holder whose “functional currency” is not the U.S. dollar;

• a “controlled foreign corporation”;

• a “passive foreign investment company”; or

• a United States expatriate.

This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), United States Treasury regulations, rulings and judicial decisions as of the date hereof. Those authorities may be changed, possibly on a retroactive basis, so as to result in U.S. federal income and estate tax consequences different from those summarized below.

If a partnership (including any entity classified as a partnership for U.S. federal income tax purposes) holds notes, the tax treatment of a partner will generally depend upon the status of the partner and the activities of the partnership. If you are a partnership or a partner in a partnership holding notes, you should consult your own tax advisors regarding the tax consequences of an investment in the notes.

This summary does not represent a detailed description of the U.S. federal income and estate tax consequences that may be applicable to you in light of your particular circumstances and does not address the effects of any state, local or non-U.S. tax laws. It is not intended to be, and should not be construed to be, legal or tax advice to any particular purchaser of notes. You should consult your own tax advisors concerning the particular U.S. federal income and estate tax consequences to you of the ownership of the notes, as well as the consequences to you arising under the laws of any other taxing jurisdiction.

Certain Tax Consequences to the Company

Because (i) the yield-to-maturity on the toggle notes equals or exceeds the sum of (x) the “applicable federal rate” (as determined under Section 1274(d) of the Code) in effect for the calendar month in which the outstanding toggle notes were issued (the “AFR”) and (y) 5 percentage points, (ii) the maturity date of the toggle notes is more than five years from the date of issue and (iii) the toggle notes have “significant” original issue discount (“OID”), the toggle notes are considered “applicable high yield discount obligations”. Therefore we will not be allowed to take a deduction for interest (including OID) accrued on the toggle notes for U.S. federal income tax purposes until such time as we actually pay such interest (including OID) in cash or in other property (other than stock or debt issued by us or by a person deemed to be related to us under Section 453(f)(1) of the Code).

Moreover, because the yield-to-maturity on the toggle notes exceeds the sum of (x) the AFR and (y) 6 percentage points (such excess shall be referred to hereinafter as the “Disqualified Yield”), the deduction for interest (including OID) accrued on the toggle notes will be permanently disallowed (regardless of whether we actually pay such interest or OID in cash or in other property) for U.S. federal income tax purposes to the extent such interest or OID is attributable to the Disqualified Yield on the toggle notes (“Dividend-Equivalent Interest”).

Certain Tax Consequences to U.S. Holders

The following is a summary of certain U.S. federal income tax consequences that will apply to U.S. holders of the notes.

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Cash-Pay Notes

Payments of Interest on Cash-Pay Notes. Interest on a cash-pay note will generally be taxable to you as ordinary income at the time it is paid or accrued in accordance with your method of accounting for U.S. federal income tax purposes.

Market Discount. If you purchase a cash-pay note for an amount that is less than its principal amount, the amount of the difference will be treated as ‘‘market discount’’ for U.S. federal income tax purposes, unless that difference is less than a specified de minimis amount. Under the market discount rules, you will be required to treat any principal payment on, or any gain on the sale, exchange, retirement or other disposition of, a cash-pay note as ordinary income to the extent of the market discount that you have not previously included in income and are treated as having accrued on the note at the time of the payment or disposition.

In addition, you may be required to defer, until the maturity of the cash-pay note or its earlier disposition in a taxable transaction, the deduction of all or a portion of the interest expense on any indebtedness attributable to the note. You may elect, on a note-by-note basis, to deduct the deferred interest expense in a tax year prior to the year of disposition. You should consult your own tax advisors before making this election.

Any market discount will be considered to accrue ratably during the period from the date of acquisition to the maturity date of the cash-pay note, unless you elect to accrue on a constant interest method. You may elect to include market discount in income currently as it accrues, on either a ratable or constant interest method, in which case the rule described above regarding deferral of interest deductions will not apply.

Amortizable Bond Premium. If you purchase a cash-pay note for an amount in excess of its principal amount, you will be considered to have purchased the cash-pay note at a “premium.” You generally may elect to amortize the premium over the remaining term of the cash-pay note on a constant yield method as an offset to interest when includible in income under your regular accounting method. If you do not elect to amortize bond premium, that premium will decrease the gain or increase the loss you would otherwise recognize on disposition of the cash-pay note.

Sale, Exchange, Retirement, or Other Taxable Disposition of Cash-Pay Notes. Upon the sale, exchange, retirement, or other taxable disposition of a cash-pay note, you generally will recognize gain or loss equal to the difference between the amount realized upon the sale, exchange, retirement or other taxable disposition (less an amount equal to any accrued interest, which will be taxable as interest income to the extent not previously included in income as discussed above) and the adjusted tax basis of the cash-pay note. Your adjusted tax basis in a cash-pay note will, in general, be your cost for that cash-pay note increased by any market discount previously included in income and reduced by any amortized premium. Except as described above with respect to market discount, any gain or loss will be capital gain or loss. Capital gains of non-corporate U.S. holders derived in respect of capital assets held for more than one year are generally eligible for reduced rates of taxation. The deductibility of capital losses is subject to limitations.

Toggle Notes

Original Issue Discount. Because the toggle notes provide us with the option to pay PIK interest in lieu of paying cash interest in any interest payment period until November 1, 2012, and because the issue price of the toggle notes is actually less than their stated redemption price at maturity, we will treat the toggle notes as having been issued with OID, as described below. The issuance of PIK Notes generally is not treated as a payment of interest. Instead, the toggle note and any PIK Notes issued in respect of PIK interest thereon are treated as a single debt instrument under the OID rules.

The toggle notes will be treated as having been issued with OID in an amount equal to the difference between their “stated redemption price at maturity” (the sum of all payments to be made on the toggle notes other than “qualified stated interest”) and their “issue price.” You generally must include OID in gross income in advance of the receipt of cash attributable to that income.

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The “issue price” of each toggle note is the first price at which a substantial amount of the outstanding toggle notes were sold (other than to an underwriter, placement agent or wholesaler). The term “qualified stated interest” means stated interest that is unconditionally payable in cash or in property (other than debt instruments of the issuer) at least annually at a single fixed rate or, subject to certain conditions, based on one or more interest indices. Because we have the option in any interest payment period until November 1, 2012 to make interest payments in PIK interest instead of paying cash, the stated interest payments on the toggle notes are not qualified stated interest.

The amount of OID that you must include in income will generally equal the sum of the “daily portions” of OID with respect to the toggle note for each day during the taxable year or portion of the taxable year in which you held such toggle note (“accrued OID”). The daily portion is determined by allocating to each day in any “accrual period” a pro rata portion of the OID allocable to that accrual period. The “accrual period” for a toggle note may be of any length and may vary in length over the term of the toggle note, provided that each accrual period is no longer than one year and each scheduled payment of principal or interest occurs on the first day or the final day of an accrual period. The amount of OID allocable to any accrual period other than the final accrual period is an amount equal to the product of the toggle note’s adjusted issue price at the beginning of such accrual period and its yield to maturity (determined on the basis of compounding at the close of each accrual period and properly adjusted for the length of the accrual period). OID allocable to a final accrual period is the difference between the amount payable at maturity and the adjusted issue price at the beginning of the final accrual period. The yield to maturity of the toggle note is the discount rate that causes the present value of all payments on the note as of its original issue date to equal the issue price of such note. For purposes of determining the yield to maturity, the assumption is that we will pay interest in cash and not exercise the option to pay PIK interest, except in respect of any period in which we actually elect to pay PIK interest.

The “adjusted issue price” of a toggle note at the beginning of any accrual period is equal to its issue price increased by the accrued OID for each prior accrual period, determined without regard to the amortization of any acquisition or bond premium, as described below, and reduced by any payments previously made on such toggle note. We are required to provide information returns stating the amount of OID accrued on toggle notes held by persons of record other than corporations and other holders exempt from information reporting.

If we in fact pay interest in cash on the toggle notes, you will not be required to adjust your OID inclusions. Each payment made in cash under a toggle note will be treated first as a payment of any accrued OID that has not been allocated to prior payments and second as a payment of principal. You generally will not be required to include separately in income cash payments received on the toggle notes to the extent such payments constitute payments of previously accrued OID or payments of principal.

With respect to any interest payment period for which we exercise our option to pay interest in the form of PIK interest, including the interest period related to the May 1, 2009 interest payment date, your OID calculation for future periods will be adjusted by treating the toggle note as if it had been retired and then reissued for an amount equal to its adjusted issue price on the date preceding the first date of such interest payment period, and re-calculating the yield to maturity of the reissued note by treating the amount of PIK interest (and of any prior PIK interest) as a payment that will be made on the maturity date of such note.

The rules regarding OID are complex and the rules described above may not apply in all cases. Accordingly, you should consult your own tax advisors regarding their application.

Applicable High Yield Discount Obligations

For purposes of the dividends-received deduction, the Dividend-Equivalent Interest, as defined above under “Certain Tax Consequences to the Company”, will be treated as a dividend to the extent it is deemed to have been paid out of our current or accumulated earnings and profits. Accordingly, if you are a corporation, you may be entitled, subject to applicable limitations, to take a dividends-received deduction with respect to any Dividend-Equivalent Interest received by you on such toggle note.

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Market Discount. If you purchase a toggle note for an amount that is less than its adjusted issue price, the amount of the difference will be treated as ‘‘market discount’’ for U.S. federal income tax purposes, unless that difference is less than a specified de minimis amount. Under the market discount rules, you will be required to treat any principal payment on, or any gain on the sale, exchange, retirement or other disposition of, a toggle note as ordinary income to the extent of the market discount that you have not previously included in income and are treated as having accrued on the note at the time of the payment or disposition.

In addition, you may be required to defer, until the maturity of the toggle note or its earlier disposition in a taxable transaction, the deduction of all or a portion of the interest expense on any indebtedness attributable to the note. You may elect, on a note-by-note basis, to deduct the deferred interest expense in a tax year prior to the year of disposition. You should consult your own tax advisors before making this election.

Any market discount will be considered to accrue ratably during the period from the date of acquisition to the maturity date of the toggle note, unless you elect to accrue on a constant interest method. You may elect to include market discount in income currently as it accrues, on either a ratable or constant interest method, in which case the rule described above regarding deferral of interest deductions will not apply.

Acquisition Premium, Amortizable Bond Premium. If you purchase a toggle note for an amount that is greater than its adjusted issue price but equal to or less than the sum of all amounts payable on the toggle note after the purchase date, you will be considered to have purchased that toggle note at an “acquisition premium.” Under the acquisition premium rules, the amount of OID that you must include in gross income with respect to the toggle note for any taxable year will be reduced by the portion of the acquisition premium properly allocable to that year.

If you purchase a toggle note for an amount in excess of the sum of all amounts payable on the toggle note after the purchase, you will be considered to have purchased the toggle note at a premium and you will not be required to include any OID in income. You generally may elect to amortize the premium over the remaining term of the toggle note on a constant yield method as an offset to interest when includible in income under your regular accounting method. If you do not elect to amortize bond premium, that premium will decrease the gain or increase the loss you would otherwise recognize on disposition of the toggle note.

Sale, Exchange, Retirement, or Other Taxable Disposition of Toggle Notes. Upon the sale, exchange, retirement, or other taxable disposition of a toggle note (or a PIK Note), you generally will recognize gain or loss equal to the difference between the amount realized upon the sale, exchange, retirement, or other taxable disposition and the adjusted tax basis of the toggle note (or the PIK Note). Your adjusted tax basis in a toggle note will, in general, be your cost for the toggle note, increased by OID or market discount previously included in income, and reduced by any amortized premium and any cash payments on the toggle note. Although not free from doubt, your adjusted tax basis in the toggle note should be allocated between the original toggle note and any PIK Notes received in respect of PIK interest thereon in proportion to their relative principal amounts. Your holding period in any PIK Note received in respect of PIK interest would likely be identical to your holding period for the original toggle note with respect to which the PIK Note was received. Except as described above with respect to market discount, any gain or loss will be capital gain or loss. Capital gains of non-corporate U.S. holders derived in respect of capital assets held for more than one year are generally eligible for reduced rates of taxation. The deductibility of capital losses is subject to limitations.

Certain Tax Consequences to Non-U.S. Holders

The following is a summary of certain U.S. federal income and estate tax consequences that will apply to non-U.S. holders of the notes.

U.S. Federal Withholding Tax. The 30% U.S. federal withholding tax will not apply to any payment of interest (which for these purposes includes OID) on the notes under the “portfolio interest rule,” provided that:

• interest paid on the notes (including OID) is not effectively connected with your conduct of a trade or business in the United States;

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• you do not actually (or constructively) own 10% or more of the total combined voting power of all classes of our voting stock within the meaning of the Code and applicable United States Treasury regulations;

• you are not a controlled foreign corporation that is related to us actually or constructively through stock ownership;

• you are not a bank whose receipt of interest (including OID) on the notes is described in Section 881(c)(3)(A) of the Code; and

• either (a) you provide your name and address on an Internal Revenue Service (“IRS”) Form W-8BEN (or other applicable form), and certify, under penalties of perjury, that you are not a United States person as defined under the Code or (b) you hold your notes through certain foreign intermediaries and satisfy the certification requirements of applicable United States Treasury regulations. Special certification rules apply to non-U.S. holders that are pass-through entities rather than corporations or individuals.

If you cannot satisfy the requirements described above, payments of interest (including OID) made to you will be subject to the 30% U.S. federal withholding tax, unless you provide us with a properly executed:

• IRS Form W-8BEN (or other applicable form) certifying an exemption from or reduction in withholding under the benefit of an applicable income tax treaty; or

• IRS Form W-8ECI (or other applicable form) certifying that interest (including OID) paid on the notes is not subject to withholding tax because it is effectively connected with your conduct of a trade or business in the United States (as discussed below under “—U.S. Federal Income Tax”).

The 30% U.S. federal withholding tax generally will not apply to any payment of principal or gain that you realize on the sale, exchange, retirement or other taxable disposition of a note.

U.S. Federal Income Tax. If you are engaged in a trade or business in the United States and interest (including OID) on the notes is effectively connected with the conduct of that trade or business (and, if required by an applicable income tax treaty, is attributable to a United States permanent establishment), then you will be subject to U.S. federal income tax on that interest (including OID) on a net income basis (although you will be exempt from the 30% U.S. federal withholding tax, provided the certification requirements discussed above in “—U.S. Federal Withholding Tax” are satisfied) in generally the same manner as if you were a U.S. holder. In addition, if you are a foreign corporation, you may be subject to a branch profits tax equal to 30% (or lower applicable income tax treaty rate) of such interest (including OID), subject to adjustments.

Any gain realized on the disposition of a note generally will not be subject to U.S. federal income tax unless:

• the gain is effectively connected with your conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, is attributable to a United States permanent establishment); or

• you are an individual who is present in the United States for 183 days or more in the taxable year of that disposition, and certain other conditions are met.

If a non-U.S. holder of notes is described in the first bullet point above, any gain realized upon a sale, exchange, retirement, or other taxable disposition of the notes will be subject to U.S. federal income tax on a net income basis. If a non-U.S. holder of notes is described in the second bullet point above, any gain realized upon a sale, exchange, retirement, or other taxable disposition of the notes will be subject to U.S. federal income tax at a statutory rate of 30%, which gain may be offset by certain losses.

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U.S. Federal Estate Tax. Your estate will not be subject to U.S. federal estate tax on notes beneficially owned by you at the time of your death, provided that any payment to you on the notes would be eligible for exemption from the 30% U.S. federal withholding tax under the “portfolio interest rule” described above under “—U.S. Federal Withholding Tax” without regard to the statement requirement described in the fifth bullet point of that section.

Information Reporting and Backup Withholding

U.S. Holders

In general, information reporting requirements will apply to certain payments of principal and interest (including OID) paid on the notes and to the proceeds of sale or other disposition (including retirement or a redemption) of a note paid to you (unless you are an exempt recipient such as a corporation). Backup withholding may apply to such payments if you fail to provide a correct taxpayer identification number or a certification that you are not subject to backup withholding.

Backup withholding is not an additional tax and any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against your U.S. federal income tax liability provided the required information is timely furnished to the IRS.

Non-U.S. Holders

In general, we must report to the IRS and to you the amount of interest (including OID) paid to you and the amount of tax, if any, withheld with respect to those payments. Copies of the information returns reporting such interest payments and any withholding may also be made available to the tax authorities in the country in which you reside under the provisions of an applicable income tax treaty.

In general, you will not be subject to backup withholding with respect to payments of interest (including OID) on the notes that we make to you provided that we do not have actual knowledge or reason to know that you are a United States person as defined under the Code and we have received from you the required certification that you are a non-U.S. holder described above in the fifth bullet point under “—Certain Tax Consequences to Non-U.S. Holders—U.S. Federal Withholding Tax.”

Information reporting and, depending on the circumstances, backup withholding will apply to the proceeds of a sale or other taxable disposition (including retirement or a redemption) of notes within the United States or conducted through certain United States-related financial intermediaries, unless you certify to the payor under penalties of perjury that you are a non-U.S. holder (and the payor does not have actual knowledge or reason to know that you are a United States person as defined under the Code), or you otherwise establish an exemption.

Backup withholding is not an additional tax and any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against your U.S. federal income tax liability provided the required information is timely furnished to the IRS.

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CERTAIN ERISA CONSIDERATIONS

The following is a summary of certain considerations associated with the outstanding notes and exchange notes by employee benefit plans that are subject to ERISA, plans, individual retirement accounts and other arrangements that are subject to Section 4975 of the Code or provisions under any other federal, state, local, non-U.S. or other laws, rules or regulations that are similar to such provisions of ERISA or the Code (collectively, “Similar Laws”), and entities whose underlying assets are considered to include “plan assets” of any such employee benefit plan, plan, account or arrangement (each, a “Plan”).

General Fiduciary Matters

ERISA and the Code impose certain duties on persons who are fiduciaries of a Plan subject to Title I of ERISA or Section 4975 of the Code (an “ERISA Plan”) and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties.

In considering an investment in the notes (or the exchange of outstanding notes for exchange notes) with a portion of the assets of any Plan, a fiduciary should determine whether the investment is in accordance with the documents and instruments governing the Plan and the applicable provisions of ERISA, the Code or any Similar Law relating to a fiduciary’s duties to the Plan including, without limitation, the prudence, diversification, delegation of control and prohibited transaction provisions of ERISA, the Code and any other applicable Similar Laws. Under ERISA and the Code, any person who exercises any discretionary authority or control over the administration of an ERISA Plan or the management or disposition of the assets of an ERISA Plan, or who renders investment advice for a fee or other compensation to an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan.

Prohibited Transaction Issues

Section 406 of ERISA and Section 4975 of the Code prohibit ERISA Plans from engaging in specified transactions involving plan assets with persons or entities who are “parties in interest,” within the meaning of ERISA, or “disqualified persons,” within the meaning of Section 4975 of the Code, unless an exemption is available. A party in interest or disqualified person who engaged in a nonexempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and/or the Code. In addition, the fiduciary of the ERISA Plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and/or the Code. The acquisition and/or holding of notes by an ERISA Plan with respect to which we are considered a party in interest or disqualified person may constitute or result in a direct or indirect prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code, unless the investment is acquired and is held in accordance with an applicable statutory, class or individual prohibited transaction exemption. Included among the exemptions that may apply to the acquisition and holding of the notes are the U.S. Department of Labor prohibited transaction class exemption (“PTCE”) 84-14 respecting transactions determined by independent qualified professional asset managers, PTCE 90-1, respecting insurance company pooled separate accounts, PTCE 91-38, respecting bank collective investment funds, PTCE 95-60, respecting life insurance company general accounts and PTCE 96-23, respecting transactions determined by in-house asset managers. In addition, Section 408(b)(17) of ERISA and Section 4975(d)(20) of the Code provide limited relief from the prohibited transaction provisions of ERISA and Section 4975 of the Code for certain transactions, provided that neither the issuer of the securities nor any of its affiliates (directly or indirectly) have or exercise any discretionary authority or control or render any investment advice with respect to the assets of any ERISA Plan involved in the transaction and provided further that the ERISA Plan pays no more than adequate consideration in connection with the transaction. There can be no assurance that all of the conditions of any such exemptions will be satisfied.

Because of the foregoing, the notes should not be acquired or held by any person investing “plan assets” of any Plan, unless such acquisition and holding will not constitute a non-exempt prohibited transaction under ERISA or Section 4975 of the Code or a similar violation under any applicable Similar Laws.

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Representation

Accordingly, by acceptance of a note or an exchange of outstanding notes for exchange notes, each holder and subsequent transferee will be deemed to have represented and warranted that either (i) no portion of the assets used by such holder or transferee to acquire or hold the notes or any interest therein constitutes assets of any Plan or (ii) the acquisition (including the exchange of outstanding notes for exchange notes) and holding of the notes or any interest therein by such holder or transferee will not constitute a non-exempt prohibited transaction under Section 406 of ERISA or Section 4975 of the Code or a similar violation under any applicable Similar Laws.

The foregoing discussion is general in nature and is not intended to be all-inclusive. Due to the complexity of these rules and the penalties that may be imposed upon persons involved in non-exempt prohibited transactions, it is particularly important that fiduciaries or other persons considering acquiring or holding the notes on behalf of, or with the assets of, any Plan, consult with their counsel regarding the potential applicability of ERISA, Section 4975 of the Code and any Similar Laws to such transactions and whether an exemption would be applicable to the acquisition and holding of the notes.

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PLAN OF DISTRIBUTION

Each broker-dealer that receives exchange notes for its own account pursuant to an exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for outstanding notes where such outstanding notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 90 days after the consummation of the exchange offers (or until the broker-dealer no longer holds registrable securities), we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, all dealers effecting transactions in the exchange notes may be required to deliver a prospectus.

We will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account pursuant to an exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices. Any such resale may be made directly to purchasers or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer and/or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to an exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an “underwriter” within the meaning of the Securities Act, and any profit of any such resale of exchange notes and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 90 days after the consummation of the exchange offers (or until the broker-dealer no longer holds registrable securities), we will promptly send additional copies of this prospectus and any amendments or supplements to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offers (including the expenses of one counsel for the holders of the outstanding notes) other than commissions or concessions of any broker-dealers and will indemnify you (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

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LEGAL MATTERS

The validity and enforceability of the exchange notes and the related guarantees will be passed upon for us by Andrew M. Wright, Vice President & Associate General Counsel of EFH Corporate Services Company, Dallas, Texas. Mr. Wright beneficially owns 75,000 shares of common stock of EFH Corp., including 25,000 shares issuable upon exercise of vested options. In addition, Mr. Wright has stock options to purchase an additional 225,000 shares of common stock of EFH Corp. at a price per share equal to $5.00.

EXPERTS

The financial statements as of December 31, 2007 (successor) and 2006 (predecessor) and 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), included in this prospectus and the related financial statement schedule included elsewhere in the registration statement of which this prospectus forms a part have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports appearing herein and elsewhere in the registration statement (which reports express an unqualified opinion on the financial statements and financial statement schedule and include an explanatory paragraph referring to the merger of EFH Corp. with Merger Sub, EFH Corp.’s adoption of FIN 39-1 and the reclassification of results of its commodity hedging and trading activities on a retrospective basis), and have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

With respect to the unaudited interim financial information for the periods ended September 30, 2008 and 2007 which is included in this prospectus, Deloitte & Touche LLP, an independent registered public accounting firm, have applied limited procedures in accordance with the standards of the Public Company Accounting Oversight Board (United States) for a review of such information. However, as stated in their report included herein (which report includes an explanatory paragraph related to the reclassification of results of EFH Corp.’s commodity hedging and trading activities on a retrospective basis), they did not audit and they do not express an opinion on that interim financial information. Accordingly, the degree of reliance on their reports on such information should be restricted in light of the limited nature of the review procedures applied. Deloitte & Touche LLP are not subject to the liability provisions of Section 11 of the Securities Act for their reports on the unaudited interim financial information because those reports are not “reports” or a “part” of the registration statement prepared or certified by an accountant within the meaning of Sections 7 and 11 of the Securities Act.

AVAILABLE INFORMATION

We and our guarantor subsidiaries have filed with the SEC a registration statement on Form S-4 under the Securities Act with respect to the exchange notes. This prospectus, which forms a part of the registration statement, does not contain all of the information set forth in the registration statement. For further information with respect to us, our guarantor subsidiaries and the exchange notes, reference is made to the registration statement. Statements contained in this prospectus as to the contents of any contract or other document are not necessarily complete.

We have historically filed annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document we have or will file with the SEC at the SEC’s public website (www.sec.gov) or at the Public Reference Room of the SEC located at 100 F Street, N.E., Washington, DC 20549. Copies of such materials can be obtained from the Public Reference Room of the SEC at prescribed rates. You can call the SEC at 1-800-SEC-0330 to obtain information on the operation of the Public Reference Room.

We and our guarantor subsidiaries have agreed that even if we are not subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act or otherwise report on an annual and quarterly basis on forms

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provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the SEC, we will nonetheless file with the SEC and make available to the trustee and to holders of notes the reports specified in “Description of Notes—Certain Covenants—Reports and Other Information,” subject to the provisions described in that section.

You should rely only upon the information provided in this prospectus. We have not authorized anyone to provide you with different information. You should not assume that the information in this prospectus is accurate as of any date other than the date of this prospectus.

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GLOSSARY

Other than under the caption “Description of the Notes,” where a different meaning for a term or abbreviation listed below is provided, when the following terms and abbreviations appear in the text of this prospectus, 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

2007 Form 10-K EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2007

2007 year-end Financial Statements These audited financial statements include the consolidated balance sheets of EFH Corp. and subsidiaries as of December 31, 2007 and 2006 and the related statements of consolidated income, comprehensive income, cash flows and shareholders’ equity for each of the three years in the period ended December 31, 2007 and the related notes to the financial statements.

Adjusted EBITDA Adjusted EBITDA means EBITDA adjusted to exclude non-cash items, unusual items and other adjustments allowable under certain debt arrangements of EFH Corp. and its subsidiaries. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. EFH Corp. is providing Adjusted EBITDA in this prospectus (see reconciliation in “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Covenants and Restrictions Under Financing Arrangements”) solely because of the important role that Adjusted EBITDA plays in respect of the certain covenants contained in EFH Corp.’s debt arrangements. EFH Corp. does not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with GAAP. Additionally, EFH Corp. does not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, EFH Corp.’s presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.

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

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Competitive Electric segment Refers to the EFH Corp. business segment, formerly referred to as the TXU Energy Holdings segment, that 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 U.S. Holdings Company), a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of TCEH.

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 U.S. Environmental Protection Agency

EPC engineering, procurement and construction

ERCOT Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas

ERISA Employee Retirement Income Security Act of 1974, as amended

Exchange Act Securities Exchange Act of 1934, as amended

FASB Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting

FERC U.S. Federal Energy Regulatory Commission

FIN Financial Accounting Standards Board Interpretation

FIN 39-1 FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39”, (Offsetting of Amounts Related to Certain Contracts—an Interpretation of APB Opinion No. 10 and FASB Statement No. 105)

FIN 46R FIN No. 46R (Revised 2003), “Consolidation of Variable Interest Entities”

FIN 47 FIN No. 47, “Accounting for Conditional Asset Retirement Obligations—An Interpretation of FASB Statement No. 143”

FIN 48 FIN No. 48, “Accounting for Uncertainty in Income Taxes”

Fitch Fitch Ratings, Ltd. (a credit rating agency)

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FSP FASB Staff Position

FSP SFAS 157-3 FASB Staff Position SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is not Active.”

GAAP generally accepted accounting principles

GWh gigawatt-hours

historical service territory the territory, largely in north Texas, being served by EFH Corp.’s regulated electric utility subsidiary at the time of entering retail competition on January 1, 2002

Intermediate Holding Refers to Energy Future Intermediate Holding Company LLC, a direct wholly-owned subsidiary of EFH Corp. established in connection with the closing of the Merger to own 100% of the equity of Oncor Holdings.

IRS U.S. Internal Revenue Service

kV kilovolts

kWh kilowatt-hours

LIBOR London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market.

Luminant Refers to wholly-owned subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.

Luminant Construction Refers to the operations of TCEH established for the purpose of developing and constructing new generation facilities.

Luminant Energy Luminant Energy Company LLC (formerly TXU Portfolio Management Company LP), an indirect wholly-owned subsidiary of TCEH that engages in certain wholesale markets activities

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.

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.

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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

NO_x nitrogen oxide

NRC U.S. 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, that is engaged in regulated electricity transmission and distribution activities.

Oncor Holdings Refers to Oncor Electric Delivery Holdings Company LLC, a direct wholly-owned subsidiary of Intermediate Holding and the direct 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

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Purchase accounting The purchase method of accounting for a business combination as prescribed by SFAS 141 whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.

Regulated Delivery segment Refers to the EFH Corp. business segment, 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 U.S. Securities and Exchange Commission

Securities Act Securities Act of 1933, as amended

September 30, 2008 Financial Statements These unaudited financial statements include the consolidated balance sheet of EFH Corp. and subsidiaries as of September 30, 2008 and December 31, 2007, and the related condensed statements of consolidated income and comprehensive income for the three- and nine-month periods ended September 30, 2008 and 2007, and of cash flows for the nine-month periods ended September 30, 2008 and 2007 and the related notes to the financial statements.

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

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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”

SFAS 160 SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51”

SFAS 161 SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an Amendment of FASB Statement No. 133”

SG&A selling, general and administrative

SO₂ sulfur dioxide

Sponsor Group Collectively, the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman Sachs & Co. (See Texas Holdings below.)

TCEH Refers to Texas Competitive Electric Holdings Company LLC, a direct wholly-owned subsidiary of EFC Holdings and an indirect wholly-owned subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation, wholesale and retail energy markets and development and construction activities. Its major subsidiaries include Luminant and TXU Energy.

TCEH Finance Refers to TCEH Finance, Inc., a direct wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities.

TCEH Senior Secured Facilities Refers collectively to the TCEH Initial Term Loan Facility, TCEH Delayed Draw Term Loan Facility, TCEH Revolving Credit Facility,

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TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 17 to the 2007 year-end 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 direct 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 direct wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT.

TXU Europe TXU Europe Limited, a subsidiary of EFH Corp. that is in administration (similar to bankruptcy) in the United Kingdom

TXU Fuel TXU Fuel Company, a former subsidiary of TCEH

TXU Gas TXU Gas Company, a former subsidiary of EFH Corp.

U.S. or US United States of America

USCAP U.S. Climate Action Partnership

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

ENERGY FUTURE HOLDINGS CORP.

Unaudited Financial Statements for the Quarterly Periods Ended September 30, 2008 and 2007
Report of Independent Registered Public Accounting Firm	F-2
Condensed Statements of Consolidated Income (Loss)—Three and Nine Months Ended September 30, 2008  and 2007	F-3
Condensed Statements of Consolidated Comprehensive Income (Loss)—Three and Nine Months Ended September  30, 2008 and 2007	F-4
Condensed Statements of Consolidated Cash Flows—Nine Months Ended September 30, 2008 and 2007	F-5
Condensed Consolidated Balance Sheets—September 30, 2008 and December 31, 2007	F-7
Notes to Condensed Consolidated Financial Statements	F-8
Audited Financial Statements for the three Fiscal Years Ended December 31, 2007
Report of Independent Registered Public Accounting Firm	F-59
Statements of Consolidated Income for each of the three years in the period ended December 31, 2007	F-60
Statements of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 2007	F-61
Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2007	F-62
Consolidated Balance sheets, December 31, 2007 and 2006	F-64
Statements of Consolidated Shareholders’ Equity for each of the three years in the period ended December  31, 2007	F-65
Notes to Financial Statements	F-66

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have reviewed the accompanying condensed consolidated balance sheet of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) as of September 30, 2008, and the related condensed statements of consolidated income (loss) and comprehensive income (loss) for the three-month and nine-month periods ended September 30, 2008 and 2007, and cash flows for the nine-month periods ended September 30, 2008 and 2007. These interim financial statements are the responsibility of EFH Corp.’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the condensed consolidated financial statements, EFH Corp. reclassified the results of its commodity hedging and trading activities on a retrospective basis.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Energy Future Holdings Corp. and subsidiaries as of December 31, 2007, 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) and the period from January 1, 2007 through October 10, 2007 (predecessor); and in our report dated March 31, 2008 (September 17, 2008 as to (1) the effects of the adoption of FASB Staff Position No. FIN 39-1 and the effects of the reclassification of results of EFH Corp.’s commodity hedging and trading activities as described in Note 1, and (2) Note 29) (which report includes an explanatory paragraph related to EFH Corp. completing its merger with Texas Energy Future Merger Sub Corp and becoming a subsidiary of Texas Energy Future Holdings Limited Partnership on October 10, 2007, EFH Corp.’s adoption of the provisions of FASB Staff Position No. FIN 39-1 and reclassification of results of its commodity hedging and trading activities on a retrospective basis), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2007 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Dallas, Texas

November 5, 2008

(November 25, 2008 as to Note 17)

F-2

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Unaudited)

(millions of dollars)

	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Operating revenues	$	3,695		$	2,983		$	9,001		$	7,743
Fuel, purchased power costs and delivery fees		(1,631	)		(882	)		(3,867	)		(2,286	)
Net gain (loss) from commodity hedging and trading activities		6,045			462			(248	)		(607	)
Operating costs		(370	)		(350	)		(1,120	)		(1,065	)
Depreciation and amortization		(431	)		(209	)		(1,217	)		(612	)
Selling, general and administrative expenses		(249	)		(229	)		(712	)		(674	)
Franchise and revenue-based taxes		(92	)		(93	)		(259	)		(269	)
Other income (Note 5)		14			20			43			65
Other deductions (Note 5)		(541	)		(10	)		(583	)		(901	)
Interest income		9			19			22			53
Interest expense and related charges (Note 15)		(831	)		(226	)		(2,505	)		(644	)
Income (loss) from continuing operations before income taxes		5,618			1,485			(1,445	)		803
Income tax (expense) benefit		(2,001	)		(506	)		462			(212	)
Income (loss) from continuing operations		3,617			979			(983	)		591
Income from discontinued operations, net of tax effect		—			13			—			24
Net income (loss)	$	3,617		$	992		$	(983	)	$	615

See Notes to Financial Statements.

F-3

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(millions of dollars)

	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Income (loss) from continuing operations	$	3,617		$	979		$	(983	)	$	591
Income from discontinued operations, net of tax effect		—			13			—			24
Net income (loss)		3,617			992			(983	)		615
Other comprehensive income (loss), net of tax effects:
Reclassification of pension and other retirement benefit costs (net of tax expense of $—, —, — and $3) (Note 11)		—			1			1			6
Cash flow hedges:
Net increase (decrease) in fair value of derivatives (net of tax (expense) benefit of $76, $(5), $99 and $155)		(141	)		7			(184	)		(290	)
Derivative value net (gains) losses related to hedged transactions recognized during the period and reported in net income (net of tax (expense) benefit of $22, $(6), $45 and $(46))		42			(10	)		84			(85	)
Total effect of cash flow hedges		(99	)		(3	)		(100	)		(375	)
Total adjustments to net income (loss)		(99	)		(2	)		(99	)		(369	)
Comprehensive income (loss)	$	3,518		$	990		$	(1,082	)	$	246

See Notes to Financial Statements.

F-4

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(millions of dollars)

	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Cash flows—operating activities:
Net income (loss)	$	(983	)	$	615
Income from discontinued operations, net of tax effect		—			(24	)
Income (loss) from continuing operations		(983	)		591
Adjustments to reconcile loss from continuing operations to cash provided by operating activities:
Depreciation and amortization		1,554			660
Deferred income tax benefit—net		(433	)		(230	)
Impairment of emission allowances intangible assets (Note 3)		501			—
Charge related to Lehman bankruptcy (Note 5)		26			—
Charge related to cancelled development of generation facilities (Note 4)		—			733
Write-off of deferred transaction costs (Note 5)		—			38
Credit related to impaired leases (Note 5)		—			(48	)
Net gains on sale of assets		(1	)		(39	)
Unrealized net losses from mark-to-market valuations of commodity positions		221			703
Unrealized net gains from mark-to-market valuations of interest rate swaps		(36	)		—
Bad debt expense		58			44
Stock-based compensation expense		26			26
Other		19			25
Changes in operating assets and liabilities:
Margin deposits—net		(236	)		(769	)
Other		241			(179	)
Cash provided by operating activities from continuing operations		957			1,555
Cash flows—financing activities:
Issuances of securities:
Pollution control revenue bonds		242			—
Other long-term debt		2,535			1,800
Common stock		34			1
Retirements/repurchases of securities:
Pollution control revenue bonds		(242	)		(143	)
Other long-term debt		(432	)		(302	)
Common stock		(1	)		(13	)
Change in short-term borrowings:
Commercial paper		—			(1,296	)
Banks		902			1,980
Common stock dividends paid		—			(594	)
Settlements of minimum withholding tax liabilities under stock-based compensation plans		—			(93	)
Debt discount, financing and reacquisition expenses		(19	)		(17	)
Other		33			—
Cash provided by financing activities		3,052			1,323

F-5

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.)

(Unaudited)

(millions of dollars)

	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Cash flows—investing activities:
Capital expenditures		(2,067	)		(2,274	)
Nuclear fuel purchases		(112	)		(54	)
Investment held in money market fund (Note 15)		(242	)		—
Purchase of mining-related assets		—			(122	)
Reduction of restricted cash related to pollution control revenue bonds		29			192
Transfer of cash collateral to custodian account (restricted cash)		(20	)		—
Other changes in restricted cash		(8	)		(11	)
Proceeds from sale of assets		53			6
Proceeds from sale of environmental allowances and credits		30			—
Purchases of environmental allowances and credits		(18	)		—
Proceeds from sales of nuclear decommissioning trust fund securities		747			402
Investments in nuclear decommissioning trust fund securities		(758	)		(413	)
Cost to remove retired property		(26	)		(24	)
Other		18			13
Cash used in investing activities		(2,374	)		(2,285	)
Discontinued operations:
Cash provided by operating activities		—			28
Cash provided by financing activities		—			—
Cash used in investing activities		—			—
Cash provided by discontinued operations		—			28
Net change in cash and cash equivalents		1,635			621
Cash and cash equivalents—beginning balance		281			25
Cash and cash equivalents—ending balance	$	1,916		$	646

See Notes to Financial Statements.

F-6

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(millions of dollars)

	Successor
	September 30, 2008			December 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	1,916		$	281
Investments held in money market fund (Note 15)		242			—
Restricted cash		84			56
Trade accounts receivable—net (Note 6)		1,234			1,099
Income taxes receivable		221			101
Inventories		412			405
Commodity and other derivative contractual assets (Note 10)		1,555			1,129
Accumulated deferred income taxes		—			9
Margin deposits related to commodity positions (Note 10)		766			513
Other current assets		140			376
Total current assets		6,570			3,969
Restricted cash		1,267			1,296
Investments		731			868
Property, plant and equipment—net		29,600			28,650
Goodwill (Note 3)		22,930			22,954
Intangible assets—net (Note 3)		3,565			4,365
Regulatory assets—net		1,419			1,305
Commodity and other derivative contractual assets (Note 10)		340			244
Unamortized debt issuance costs and other noncurrent assets		1,069			1,130
Assets held for sale		—			23
Total assets	$	67,491		$	64,804
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings (Note 7)	$	2,620		$	1,718
Long-term debt due currently (Note 7)		416			513
Trade accounts payable		1,223			904
Commodity and other derivative contractual liabilities (Note 10)		2,006			1,146
Margin deposits related to commodity positions (Note 10)		22			5
Accrued interest		875			537
Other current liabilities		588			879
Total current liabilities		7,750			5,702
Accumulated deferred income taxes		6,528			6,664
Investment tax credits		43			47
Commodity and other derivative contractual liabilities (Note 10)		2,456			2,453
Long-term debt, less amounts due currently (Note 7)		40,867			38,603
Other noncurrent liabilities and deferred credits		4,214			4,650
Total liabilities		61,858			58,119
Commitments and Contingencies (Note 8)
Shareholders’ equity (Note 9)
Common stock without par value: Authorized shares—2,000,000,000 Outstanding shares 1,667,055,540 and 1,664,345,953		—			—
Additional paid-in capital		8,309			8,279
Retained deficit		(2,343	)		(1,360	)
Accumulated other comprehensive loss		(333	)		(234	)
Total shareholders’ equity		5,633			6,685
Total liabilities and shareholders’ equity	$	67,491		$	64,804

See Notes to Financial Statements.

F-7

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

EFH Corp., a Texas corporation, is a Dallas-based holding company conducting its operations principally through its TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including 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 described in the 2007 Form 10-K, various “ring-fencing” measures have been taken to further separate Oncor from the other EFH Corp. businesses. Under such provisions, the assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of Texas Holdings, EFH Corp. and EFH Corp.’s other subsidiaries, including TXU Energy and Luminant, and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or other obligations of Texas Holdings, EFH Corp. or EFH Corp.’s other subsidiaries. Moreover, the cash flows of the Oncor Ring-Fenced Entities and their results of operations are separate from those of Texas Holdings, EFH Corp. and EFH Corp.’s other subsidiaries.

EFH Corp. has two reportable segments: the Competitive Electric segment, which includes the activities of TCEH as well as equipment salvage and resale activities related to the 2007 cancelled development of new generation facilities, and the Regulated Delivery segment, which includes the activities of Oncor, its wholly-owned bankruptcy-remote financing subsidiary and, in 2007, certain revenues and costs associated with installation of equipment that will facilitate Oncor’s technology initiatives. See Note 14 for further information concerning reportable business segments.

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.

See Note 16 for discussion of Oncor’s sale of approximately 20% of its outstanding equity interest on November 5, 2008.

Basis of Presentation

The condensed consolidated financial statements of EFH Corp. have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in its 2007 Form 10-K, with the exception of a change to discontinue the netting of derivative assets and liabilities under master netting agreements as allowed under FIN 39-1, a change in classification to report the results of commodity hedging and trading activities on a separate line item in the income statement instead of within operating revenues, as discussed below, and certain reclassifications in the condensed statements of comprehensive income (loss) to conform to current period presentation. All adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes included in the 2007 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.

F-8

The accompanying condensed statements of consolidated income (loss) and comprehensive income (loss) for the three and nine months ended September 30, 2008 and September 30, 2007 and consolidated cash flows for the nine months ended September 30, 2008 and September 30, 2007 are presented as the “Successor” and the “Predecessor,” and relate to periods succeeding and preceding the Merger, respectively. The consolidated financial statements of the Successor reflect the application of purchase accounting in accordance with the provisions of SFAS 141.

Change in Classification of Results from Commodity Hedging and Trading Activities—Effective April 1, 2008, EFH Corp. changed its classification of realized and unrealized net gains and losses from commodity hedging and trading activities such that the results from these activities are reported as a separate line on the income statement. Prior to April 1, 2008, such amounts were included within operating revenues. EFH Corp. believes this change in classification provides users of the financial statements better transparency of underlying revenue trends. Results from commodity hedging and trading activities are volatile as a substantial majority of the activity involves natural gas financial instruments, which are used to economically hedge future cash flows from electricity sales and are marked-to-market in net income. Comparative financial statements of prior periods reflect this reclassification. The following table presents EFH Corp.’s operating revenues as previously reported and reflects the change in classification. There is no effect on reported earnings, the balance sheet or the statement of cash flows as a result of this change in presentation.

	Predecessor
	As Originally Reported		As Reclassified		As Originally Reported		As Reclassified
	Three Months Ended September 30, 2007		Three Months Ended September 30, 2007		Nine Months Ended September 30, 2007		Nine Months Ended September 30, 2007
Operating revenues	$	3,445	$	2,983	$	7,136	$	7,743
Net gain (loss) from commodity hedging and trading activities		n/a		462		n/a		(607	)
Income from continuing operations		979		979		591		591

Discontinued Businesses

Income from discontinued operations in the nine months ended September 30, 2007 consisted primarily of insurance proceeds related to the 2005 TXU Europe litigation settlement agreement.

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.

F-9

Changes in Accounting Standards

Effective January 1, 2008, EFH Corp. adopted FSP FIN 39-1, “Amendment of FASB Interpretation No. 39.” This FSP provides additional guidance regarding the offsetting in the balance sheet of cash collateral and derivative fair value asset and liability amounts. As provided for by this rule, for balance sheet presentation, EFH Corp. elected to not adopt netting of cash collateral, and further to discontinue netting of derivative assets and liabilities under master netting agreements. Accordingly, as required by the rule, prior period amounts in the financial statements reflect the change in presentation, resulting in an increase of $849 million and $171 million in both commodity and other derivative contractual current and noncurrent assets and liabilities, respectively, at December 31, 2007 compared to amounts previously reported in the 2007 Form 10-K.

In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities—an Amendment of FASB Statement 133.” SFAS 161 enhances required disclosures regarding derivatives and hedging activities to enable investors to better understand their effects on an entity’s financial position, financial performance and cash flows. This statement is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. EFH Corp. is evaluating the impact of this statement on its financial statement disclosures.

In October 2008, the FASB issued FSP SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active.” The FSP clarifies the application of SFAS 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. The FSP does not change the fair value measurement principles in SFAS 157. The FSP is effective upon issuance, including prior periods for which financial statements have not been issued. EFH Corp. has determined this FSP does not change its approach for measuring fair value of financial assets.

2. FINANCIAL STATEMENT EFFECTS OF THE MERGER

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 totals $22.9 billion as of September 30, 2008. 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 September 30, 2008 is substantially complete; however, additional analysis with respect to the value of certain assets, contractual arrangements and contingent liabilities could result in a change in the total amount of goodwill and amounts assigned to EFH Corp.’s reporting units. SFAS 141 requires that the purchase price allocation be completed no later than one year from the date of the Merger.

F-10

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	$	28,390
Intangible assets		4,462
Regulatory assets and deferred debits		1,447
Other assets		4,890
Total assets acquired		39,189
Short-term borrowings and long-term debt		14,183
Deferred income tax liabilities		7,871
Other liabilities		7,371
Total liabilities assumed		29,425
Net identifiable assets acquired.				9,764
Goodwill.			$	22,930

Exit liabilities originally recorded as part of the purchase price allocation totaled approximately $60 million, which consisted primarily of estimated amounts related to the cancellation of the development of coal-fueled generation facilities discussed in Note 4 and the exit of certain administrative activities. Such cancellation liabilities have been negotiated to a lesser amount and taking into consideration payments made, the exit liabilities have all been extinguished as of September 30, 2008. In September 2008, additional exit liabilities totaling $10 million related to termination pursuant to the Merger of certain contractual agreements were recorded. This amount is expected to be paid by the first quarter of 2009.

The decrease in exit liabilities discussed immediately above was the principal cause of a $24 million decrease in goodwill between December 31, 2007 and September 30, 2008.

Unaudited Pro Forma Financial Information

The following unaudited pro forma results of operations assume that the Merger-related transactions occurred on January 1, 2007. The unaudited pro forma information is provided for informational purposes only and is not necessarily indicative of what EFH Corp.’s results of operations would have been if the Merger-related transactions had occurred on that date, or what EFH Corp.’s results of operations will be for any future periods.

For the three months ended September 30, 2007, unaudited pro forma revenues and net income were $2.985 billion and $453 million, respectively. Pro forma adjustments for the three months ended September 30, 2007 consist of incremental depreciation and amortization expense (including amounts recognized in revenues or fuel and purchased power costs) of $151 million, interest expense of $678 million and income tax benefits of $290 million. For the nine months ended September 30, 2007, unaudited pro forma revenues and net loss were $7.750 billion and $1.001 billion, respectively. Pro forma adjustments for the nine months ended September 30, 2007 consist of incremental depreciation and amortization expense (including amounts recognized in revenues or fuel and purchased power costs) of $453 million, interest expense of $2.034 billion and income tax benefits of $870 million.

F-11

3. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

Goodwill as of September 30, 2008 totaled $22.930 billion with $18.033 billion assigned to the Competitive Electric segment and $4.897 billion to the Regulated Delivery segment. Goodwill as of December 31, 2007 totaled $22.954 billion with $18.060 billion assigned to the Competitive Electric segment and $4.894 billion to the Regulated Delivery segment. None of this goodwill balance is being deducted for tax purposes.

Assessment of Goodwill Impairment

Key measures in assessing the fair value of EFH Corp., including equity values of comparable companies and forward natural gas prices, experienced significant volatility and general declines in the third quarter as the credit crisis has impacted worldwide markets. As a result of these market movements, management considered whether an assessment of the carrying value of goodwill, in accordance with the provisions of SFAS 142, should be performed as of September 30, 2008 for its reporting units, which consist of its Competitive Electric and Regulated Delivery segments.

In consideration of long-term valuation drivers and trends specific to EFH Corp. and recently completed and proposed relevant transactions, management believes that the fundamental value of the business has not changed materially, and considering the volatility in the markets during September 2008, determined that it would be premature to conclude that market declines as of the end of the third quarter are other than temporary. Management intends to reassess market conditions prior to the issuance of EFH Corp.’s year-end financial statements. EFH Corp.’s annual goodwill assessment date under SFAS 142 falls in the fourth quarter. Management believes that any potential impairment of goodwill would be limited to the Competitive Electric segment, as equity values of many unregulated wholesale electricity generation entities have been impacted by the market turmoil (and in some cases by factors specific to a company’s circumstances), while those of regulated electricity transmission and distribution entities largely have been stable.

Under the SFAS 142 goodwill impairment analysis, if at the assessment date the Competitive Electric segment’s carrying value exceeded its estimated enterprise value, then the estimated enterprise value of the segment would be compared to the estimated fair values of the segment’s operating assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill amount would then be compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied goodwill amount would be written off as an impairment charge. Because any decline in enterprise value would likely be accompanied by a decline in the fair value of assets, particularly generation plants, it is possible that implied goodwill would approximate recorded goodwill, and no impairment would arise as a result of this analysis.

F-12

Identifiable Intangible Assets

Identifiable intangible assets are comprised of the following:

	Successor
	As of September 30, 2008						As of December 31, 2007
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	118	$	345	$	463	$	79	$	384
Favorable purchase and sales contracts		715		197		518		702		68		634
Capitalized in-service software		248		104		144		225		71		154
Environmental allowances and credits		984		96		888		1,525		19		1,506
Land easements and other		190		70		120		179		67		112
Total intangible assets subject to amortization	$	2,600	$	585		2,015	$	3,094	$	304		2,790
Trade name (not subject to amortization)						1,436						1,436
Mineral interests (not currently subject to amortization)						114						139
Total intangible assets					$	3,565					$	4,365

Amortization expense related to intangible assets consisted of:

	Successor		Predecessor		Successor		Predecessor
	Three Months Ended September 30, 2008		Three Months Ended September 30, 2007		Nine Months Ended September 30, 2008		Nine Months Ended September 30, 2007
Retail customer relationship	$	13	$	—	$	39	$	—
Favorable purchase and sales contracts		9		—		115		—
Capitalized in-service software		11		8		33		21
Environmental allowances and credits		28		—		77		—
Land easements		1		—		2		2
Total amortization expense	$	62	$	8	$	266	$	23

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

• Retail Customer Relationship—Retail customer relationship intangible asset represents the 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 the retail customer relationship intangible asset is reported as part of depreciation and amortization expense in the income statement (reported in the Competitive Electric segment).

• Favorable Purchase and Sales Contracts—Favorable purchase and sales contracts intangible asset primarily represents the above market value of commodity contracts for which: 1) EFH Corp. has made the “normal” purchase or sale election allowed by SFAS 133 or 2) the contracts did not meet the definition of a derivative. The amortization periods of these intangible assets are based on the terms of the contracts, and the expense is reported as part of revenues or fuel and purchased power costs in the income statement as appropriate (reported in the Competitive Electric segment). Unfavorable purchase and sales contracts are recorded as other noncurrent liabilities and deferred credits (see Note 15).

F-13

• 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.”

• Environmental Allowances and Credits—This intangible asset represents the fair value of environmental allowances and credits held by EFH Corp., substantially all of which were expected to be used in its power generation activity. These credits will be amortized to fuel and purchased power costs utilizing a units-of-production method (reported in the Competitive Electric segment).

Impairment of Certain Intangible Assets

In March 2005, the EPA issued regulations called the Clean Air Interstate Rule (CAIR) for 28 states, including Texas, where EFH Corp.’s generation facilities are located. CAIR required reductions of SO₂ and NOx emissions from power generation facilities in such states. The SO₂ reductions were beyond the reductions required under the Clean Air Act’s existing acid rain cap-and-trade program (the Acid Rain Program). CAIR also established a new regional cap-and-trade program for NOx emissions reductions.

In July 2008, the US Court of Appeals for the D.C. Circuit (the D.C. Circuit Court) invalidated CAIR. The D.C. Circuit Court did not overturn the existing cap-and-trade program for SO₂ reductions under the Acid Rain Program.

In the second quarter of 2008, EFH Corp. determined that certain of its SO₂ allowances had decreased materially in value, likely driven by litigation that resulted in the July 2008 decision from the D.C. Circuit Court invalidating CAIR. Accordingly, EFH Corp. recorded a $2 million (before deferred income tax benefit) impairment of certain SO₂ allowances.

Based on the D.C. Circuit Court’s ruling, EFH Corp. recorded a non-cash impairment charge to earnings in the third quarter of 2008. EFH Corp. impaired NOx allowances in the amount of $401 million (before deferred income tax benefit). As a result of the D.C. Circuit Court’s decision, as it stands, NOx allowances would no longer be needed, and thus there would not be an actively traded market for such allowances. Consequently, the NOx allowances held by EFH Corp. would likely have very little value absent reversal of the D.C. Circuit Court’s decision or promulgation of new rules by the EPA. In addition, EFH Corp. impaired SO₂ allowances in the amount of $98 million (before deferred income tax benefit). While the D.C. Circuit Court did not invalidate the Acid Rain Program, EFH Corp. would have more SO₂ allowances than it would need to comply with the Acid Rain Program. While there continues to be a market for SO₂ allowances, the D.C. Circuit Court’s decision has resulted in a material decrease in the market price of SO₂ allowances.

The impairment amounts recorded in the second and third quarters of 2008 were reported in other deductions and are reflected in the results of the Competitive Electric segment.

At this time EFH Corp. cannot predict the final outcome of the D.C. Circuit Court’s decision, including whether the D.C. Circuit Court will grant the EPA’s request for rehearing or revise its decision to allow CAIR to remain in place during any Court-ordered revision of CAIR by the EPA.

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	$	375
2009		475
2010		284
2011		234
2012		165

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4. CHARGES RELATED TO CANCELLED DEVELOPMENT OF COAL-FUELED GENERATION FACILITIES

In the first quarter of 2007, EFH Corp. recorded a charge totaling $713 million ($463 million after-tax) in connection with the suspension in February 2007 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 charge included $673 million for the impairment of construction work-in-process asset balances (primarily pre-construction development costs), $11 million for costs arising from terminations of equipment orders and $29 million for the write-off of deferred financing costs. In determining the charge to be recorded, EFH Corp. applied accounting rules for impairment of long-lived assets under SFAS 144 and for exit activities under SFAS 146. As disclosed in the 2007 Form 10-K, $44 million ($29 million after-tax) in net charges related to these units were recorded in subsequent periods of 2007, including net charges of $17 million ($11 million after-tax) recorded in the third quarter of 2007. Additional charges totaling $2 million and $10 million ($1 million and $6 million after-tax, respectively) were recorded in the three and nine months ended September 30, 2008, respectively, which primarily represented costs for transportation and storage of materials.

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 September 30, 2008 totaled $88 million and consisted of estimated recovery amounts, using a probability-weighted methodology, from equipment salvage and potential resale activities. Cumulative net cash proceeds through September 30, 2008 from the sale of the impaired assets total $169 million.

Subsidiaries of EFH Corp. have terminated all of the equipment orders, with the exception of one purchase order for a boiler that is expected to be resold, and the air permit applications related to the eight units were formally withdrawn from the TCEQ in October 2007 after the close of the Merger. The net charges arising from cancellation of this development program have been classified in other deductions and are reported in the results of the Competitive Electric segment.

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5. OTHER INCOME AND DEDUCTIONS

	Successor		Predecessor			Successor		Predecessor
	Three Months Ended September 30, 2008		Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008		Nine Months Ended September 30, 2007
Other income:
Amortization of gain on sale of TXU Fuel business	$	—	$	12		$	—	$	35
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting (see Note 15)		11		—			33		—
Net gain on sale of assets		1		—			1		4
Adjustments to insurance reserves related to discontinued operations		—		—			—		7
Penalty received for nonperformance under a coal transportation agreement		—		3			—		6
Mineral rights royalty income		1		3			3		8
Other		1		2			6		5
Total other income	$	14	$	20		$	43	$	65
Other deductions:
Impairment of emission allowances intangible assets (Note 3)		499		—			501		—
Charge related to Lehman bankruptcy (a)		26		—			26		—
Transition and business optimization costs		8		—			8		—
Net charges related to cancelled development of generation facilities (Note 4)		2		17			10		812
Charge related to termination of rail car lease (b)		—		10			—		10
Other asset writeoffs (c)		—		4			2		34
Professional fees incurred related to the Merger		1		18			4		38
Expenses related to InfrastruX Energy Services joint venture (d)		—		—			—		12
Credit related to impaired leases (e)		—		(48	)		—		(48	)
Costs related to 2006 cities rate settlement		—		6			13		19
Litigation/regulatory settlements		—		—			6		5
Ongoing pension and other postretirement benefit expense (credit) related to discontinued businesses		1		1			2		10
Other		4		2			11		9
Total other deductions	$	541	$	10		$	583	$	901

(a) Represents reserve established against amounts due (excluding termination related costs) from subsidiaries of Lehman Brothers Holdings Inc. arising from commodity hedging and trading activities. There are no open positions with these subsidiaries. (Reported in Competitive Electric segment.)

(b) Represents costs associated with termination and refinancing of a rail car lease. (Reported in Competitive Electric segment.)

F-16

(c) $30 million of the nine months ended September 30, 2007 amount 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 were no longer expected to be consummated as a result of the Merger. (Reported in Corporate and Other activities.)

(d) Consists of previously deferred costs, consisting primarily of professional fees that were written off due to suspension of the joint venture arrangement, which was cancelled in connection with the Merger. Of these amounts, $8 million was reported in the Corporate and Other activities and the balance was reported in the Regulated Delivery segment results.

(e) 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 were no longer operated for its own benefit. In the third quarter of 2007, a 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. operates these assets for its own benefit after the Merger.

6. TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

Sale of Receivables

Subsidiaries of EFH Corp. engaged in retail sales of electricity participate in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with SFAS 140. Under the program, such subsidiaries (originators) sell trade accounts receivable to TXU Receivables Company, 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).

As of September 30, 2008, program funding was $700 million, which is the maximum amount currently available under the accounts receivable securitization program. The amount of customer deposits held by the originators can reduce the amount of undivided interests that can be sold, thus reducing funding available under the program, during periods in which TCEH’s long-term senior unsecured debt rating is lower than investment grade. Funding availability for all originators can be reduced by 100% of the originators’ customer deposits if TCEH’s credit rating is lower than Ba3/BB-; 50% if TCEH’s credit rating is between Ba3/BB- and Ba1/BB+; and zero % if TCEH’s credit rating is at least Baa3/BBB-. Although TCEH’s credit ratings were lower than Ba3/BB- as of September 30, 2008, the originators’ customer deposits, which totaled $111 million, did not reduce funding availability at that date since the amount of undivided interests that otherwise could be sold exceeded the $700 million program limit.

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 $340 million and $296 million at September 30, 2008 and December 31, 2007, 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 wholly-owned 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

F-17

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			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Program fees	$	7		$	10		$	18		$	30
Program fees as a percentage of average funding (annualized)		4.2	%		6.0	%		5.2	%		6.3	%
Servicing fees		1			1			3			3

The accounts receivable balance reported in the September 30, 2008 consolidated balance sheet includes $1.040 billion face amount of trade accounts receivable of TCEH subsidiaries sold to TXU Receivables Company, such amount having been reduced by $700 million of undivided interests sold by TXU Receivables Company. Funding under the program increased $337 million and $73 million for the nine month periods ending September 30, 2008 and 2007, respectively. 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
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Cash collections on accounts receivable	$	4,881		$	6,066
Face amount of new receivables purchased		(5,263	)		(6,446	)
Discount from face amount of purchased receivables		22			33
Program fees paid		(18	)		(30	)
Servicing fees paid		(3	)		(3	)
Increase in subordinated notes payable		44			307
Operating cash flows provided to EFH Corp. under the program	$	(337	)	$	(73	)

Effective with the completion of the Merger, Oncor no longer participates in the accounts receivable securitization program. Amounts funded under the program related to Oncor’s trade accounts receivable totaled $112 million at September 30, 2007. Amounts related to Oncor’s trade accounts receivable for the nine months ended September 30, 2007 totaled $5 million in program fees and $26 million in operating cash flows provided.

The program may be terminated upon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds, and the financial institutions do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables, not separately to the receivables of each originator. In addition, the program may be terminated if TXU Receivables Company or EFH Corporate Services Company, as collection agent, shall default in any payment with respect to debt in excess of $50,000 in the aggregate for TXU Receivables Company and EFH Corporate Services Company, or if TCEH, any affiliate of TCEH acting as collection agent under the program other than EFH Corporate Services Company, any parent guarantor of an originator or any originator shall default in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities.

F-18

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
	September 30, 2008			December 31, 2007
Gross trade accounts receivable	$	2,003		$	1,494
Undivided interests in accounts receivable sold by TXU Receivables Company		(700	)		(363	)
Allowance for uncollectible accounts		(69	)		(32	)
Trade accounts receivable—reported in balance sheet	$	1,234		$	1,099

Gross trade accounts receivable at September 30, 2008 and December 31, 2007 included unbilled revenues of $522 million and $477 million, respectively.

Allowance for Uncollectible Accounts Receivable

	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Allowance for uncollectible accounts receivable as of beginning of period	$	32		$	13
Increase for bad debt expense		58			44
Decrease for account writeoffs		(47	)		(45	)
Charge related to Lehman bankruptcy		26			—
Changes related to receivables sold		—			11
Allowance for uncollectible accounts receivable as of end of period	$	69		$	23

Allowances related to undivided interests in receivables sold totaled $15 million at September 30, 2007, and this amount was reported in current liabilities.

7. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

At September 30, 2008, EFH Corp. and its subsidiaries had outstanding short-term borrowings of $2.620 billion at a weighted average interest rate of 5.88%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $2.470 billion for TCEH and $150 million for Oncor.

At December 31, 2007, EFH Corp. and its subsidiaries had outstanding short-term borrowings of $1.718 billion at a weighted average interest rate of 5.39%, excluding certain customary fees, at the end of the period. Borrowings under credit facilities totaled $1.280 billion for Oncor and $438 million for TCEH.

F-19

Credit Facilities

EFH Corp.’s credit facilities with cash borrowing and/or letter of credit availability at September 30, 2008 are presented below. The facilities are all senior secured facilities of the authorized borrower.

		At September 30, 2008
Authorized Borrowers and Facility	Maturity Date	Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Delayed Draw Term Loan Facility (a)	October 2014	$	4,100	$	—	$	3,154	$	946
TCEH Revolving Credit Facility (b)	October 2013		2,700		102		1,910		688
TCEH Letter of Credit Facility (c)	October 2014		1,250		—		1,250		—
Subtotal TCEH		$	8,050	$	102	$	6,314	$	1,634
TCEH Commodity Collateral Posting Facility (d)	December 2012		Unlimited	$	—	$	969		Unlimited
Oncor Revolving Credit Facility (e)	October 2013	$	2,000	$	—	$	150	$	1,850

(a) Facility to be used during the two-year period commencing on October 10, 2007 to fund expenditures for constructing certain new generation facilities and environmental upgrades of existing generation facilities, including previously incurred expenditures not yet funded under this facility. Borrowings are classified as long-term debt.

(b) Facility to be used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings.

(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 $1.131 billion issued as of September 30, 2008 are supported by the restricted cash, and the remaining letter of credit availability totals $119 million.

(d) Revolving facility to be used to fund cash collateral posting requirements for specified volumes of natural gas hedges. At September 30, 2008, cash borrowings of $409 million are classified as long-term debt and $560 million are classified as short-term borrowings.

(e) Facility to be used by Oncor for its general corporate purposes. Borrowings are classified as short-term borrowings. The year-to-date decrease in borrowing from $1.280 billion to $150 million was driven by the use of the majority of the proceeds from the issuance in September 2008 of $1.500 billion of senior secured notes as described below under “Debt Related Activity in 2008” to repay short-term borrowings.

The availability amounts shown above include unfunded commitments from a subsidiary of Lehman Brothers Holdings Inc. (Lehman) that has filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. As of September 30, 2008, the aggregate amounts of such unfunded commitments were $79 million under the TCEH Revolving Credit Facility, $16 million under the TCEH Delayed Draw Term Loan Facility and $159 million under the Oncor Revolving Credit Facility. In addition, the amount of letters of credit shown above for the TCEH Revolving Credit Facility include approximately $12 million for the account of the Lehman subsidiary, and the amount of cash borrowings shown above for the TCEH Revolving Credit Facility include approximately $80 million funded by a fronting bank on behalf of the Lehman subsidiary that had not been reimbursed to the fronting bank as of September 30, 2008. See Note 5 for discussion of a charge recorded related to other transactions with Lehman.

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 September 30, 2008, the total availability under the TCEH credit facilities should be further reduced by $120 million.

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Long-Term Debt

At September 30, 2008 and December 31, 2007, the long-term debt of EFH Corp. consisted of the following:

	Successor
	September 30, 2008			December 31, 2007
TCEH
Pollution Control Revenue Bonds:
Brazos River Authority:
5.400% Fixed Series 1994A due May 1, 2029	$	39		$	39
7.700% Fixed Series 1999A due April 1, 2033		111			111
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013 (a)		16			16
7.700% Fixed Series 1999C due March 1, 2032		50			50
8.250% Fixed Series 2001A due October 1, 2030		71			—
2.300% Floating Series 2001A due October 1, 2030 (b)		—			71
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011 (a)		217			217
8.250% Fixed Series 2001D-1 due May 1, 2033		171			—
2.300% Floating Series 2001D-1 due May 1, 2033 (b)		—			171
8.230% Floating Series 2001D-2 due May 1, 2033 (c)		97			97
8.000% Floating Taxable Series 2001I due December 1, 2036 (c)		62			62
8.230% Floating Series 2002A due May 1, 2037 (c)		45			45
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (a)		44			44
6.300% Fixed Series 2003B due July 1, 2032		39			39
6.750% Fixed Series 2003C due October 1, 2038		52			52
5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014 (a)		31			31
5.000% Fixed Series 2006 due March 1, 2041		100			100
Sabine River Authority of Texas:
6.450% Fixed Series 2000A due June 1, 2021		51			51
5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011 (a)		91			91
5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011 (a)		107			107
5.200% Fixed Series 2001C due May 1, 2028		70			70
5.800% Fixed Series 2003A due July 1, 2022		12			12
6.150% Fixed Series 2003B due August 1, 2022		45			45
Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028		14			14
Unamortized fair value discount related to pollution control revenue bonds (d)		(165	)		(175	)
Senior Secured Facilities:
6.248% TCEH Initial Term Loan Facility maturing October 10, 2014 (e)(f)		16,286			16,409
6.222% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (e)(f)		3,154			2,150
5.989% TCEH Letter of Credit Facility maturing October 10, 2014 (f)		1,250			1,250
3.831% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (g)		409			382
Other:
10.25% Fixed Senior Notes due November 1, 2015		3,000			3,000
10.25% Fixed Senior Notes Series B due November 1, 2015		2,000			2,000
10.50 / 11.25% Senior Toggle Notes due November 1, 2016		1,750			1,750
6.125% Fixed Senior Notes due March 15, 2008		—			3
7.000% Fixed Senior Notes due March 15, 2013		5			5
7.100% Promissory Note due January 5, 2009		65			65
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		67			78
Capital lease obligations		161			161
Unamortized fair value discount (d)		(8	)		(9	)
Total TCEH	$	29,509		$	28,604

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	Successor
	September 30, 2008			December 31, 2007
EFC Holdings
9.580% Fixed Notes due in semiannual installments through December 4, 2019	$	58		$	59
8.254% Fixed Notes due in quarterly installments through December 31, 2021		54			56
3.601% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (f)		1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037		8			8
Unamortized fair value discount (d)		(13	)		(14	)
Total EFC Holdings		108			110
EFH Corp.
10.875% Fixed Senior Notes due November 1, 2017		2,000			2,000
11.25 / 12.00% Senior Toggle Notes due November 1, 2017		2,500			2,500
6.375% Fixed Senior Notes Series C due January 1, 2008		—			200
4.800% Fixed Senior Notes Series O due November 15, 2009		3			3
5.550% Fixed Senior Notes Series P due November 15, 2014		1,000			1,000
6.500% Fixed Senior Notes Series Q due November 15, 2024		750			750
6.550% Fixed Senior Notes Series R due November 15, 2034		750			750
8.820% Building Financing due semiannually through February 11, 2022 (h)		80			88
Unamortized fair value premium related to Building Financing (d)		22			24
Unamortized fair value discount (d)		(674	)		(714	)
Total EFH Corp.		6,431			6,601
Oncor
6.375% Fixed Senior Notes due May 1, 2012 (i)		700			700
5.950% Fixed Senior Notes due September 1, 2013 (i)		650			—
6.375% Fixed Senior Notes due January 15, 2015 (i)		500			500
6.800% Fixed Senior Notes due September 1, 2018 (i)		550			—
7.000% Fixed Debentures due September 1, 2022 (i)		800			800
7.000% Fixed Senior Notes due May 1, 2032 (i)		500			500
7.250% Fixed Senior Notes due January 15, 2033 (i)		350			350
7.500% Fixed Senior Notes due September 1, 2038 (i)		300			—
Unamortized discount		(17	)		(15	)
Total Oncor		4,333			2,835
Oncor Electric Delivery Transition Bond Company LLC (j)
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		54			93
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		130			130
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		145			145
3.520% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2009		71			99
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		221			221
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		290			290
Total Oncor Electric Delivery Transition Bond Company LLC		911			978
Unamortized fair value discount related to transition bonds (d)		(9	)		(12	)
Total Oncor consolidated		5,235			3,801
Total EFH Corp. consolidated		41,283			39,116
Less amount due currently		(416	)		(513	)
Total long-term debt	$	40,867		$	38,603

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

(b) Interest rates in effect at March 31, 2008. These series were remarketed in June 2008, resulting in a fixed rate to maturity.

(c) Interest rates in effect at September 30, 2008. 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.

F-22

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

(e) Interest rate swapped to fixed on $16.55 billion principal amount.

(f) Interest rates in effect at September 30, 2008.

(g) Interest rates in effect at September 30, 2008, excluding quarterly maintenance fee discussed below. See “Credit Facilities” above for more information.

(h) This financing is secured with a $121 million letter of credit.

(i) Secured with first priority lien as discussed under “Oncor Revolving Credit Facility” below.

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

Debt-Related Activity in 2008—Retirements of long-term debt in 2008 totaling $674 million represented principal payments at scheduled maturity dates as well as the remarketing of $242 million principal amount of pollution control revenue bonds discussed below. Payments at scheduled maturity dates included $200 million of EFH Corp. senior notes, $123 million repaid under the TCEH Initial Term Loan Facility, and $67 million of Oncor transition bond principal payments.

Issuances of long-term debt in 2008 totaling $2.777 billion represented senior secured notes issued by Oncor with an aggregate principal amount of $1.500 billion (see discussion below under “Oncor Senior Secured Notes”), borrowings under the TCEH Delayed Draw Term Loan Facility of $1.004 billion to fund expenditures related to the development of new generation facilities and the environmental retrofit program for existing lignite/coal-fueled generation facilities, the remarketing of $242 million principal amount of pollution control revenue bonds discussed immediately below and $31 million of additional borrowings under the TCEH Commodity Collateral Posting Facility (under which additional borrowings in 2008 totaling $122 million are classified as short-term debt).

In June 2008, TCEH remarketed the Brazos River Authority Pollution Control Revenue Bonds Series 2001A due in October 2030 and Series 2001D-1 due in May 2033 with aggregate principal amounts of $71 million and $171 million, respectively. The bonds were previously in a floating rate mode that reset weekly and were backed by two letters of credit in an aggregate amount of $247 million. As a result of the remarketing, the bonds were fixed to maturity at an interest rate of 8.25%, and the two letters of credit were cancelled. The bonds are redeemable at par beginning July 1, 2018 and are redeemable with a make-whole premium prior to July 1, 2018. These bonds were remarketed with a covenant package similar to the notes discussed below under “TCEH Notes Issued Subsequent to the Merger.”

TCEH Senior Secured Facilities—Borrowings under the TCEH Initial Term Loan Facility, the TCEH Delayed Draw Term Loan Facility, the TCEH Revolving Credit Facility and the TCEH Letter of Credit Facility, which totaled $22.600 billion at September 30, 2008, bear interest at per annum rates equal to, at TCEH’s option, (i) adjusted LIBOR plus 3.50% or (ii) a base rate (the higher of (1) the prime rate as announced from time to time by the administrative agent of the facilities and (2) the federal funds effective rate plus 0.50%) plus 2.50%. There is a margin adjustment mechanism in relation to term loans, revolving loans and letter of credit fees under which the applicable margins may be reduced based on the achievement of certain leverage ratio levels; there was no such reduction based upon September 30, 2008 levels. The applicable rate on each facility as of September 30, 2008 is provided in the table above and reflects LIBOR-based borrowings.

A commitment fee is payable quarterly in arrears and upon termination of the TCEH Revolving Credit Facility at a rate per annum equal to 0.50% of the average daily unused portion of such facility. The commitment fee is subject to reduction, based on the achievement of certain leverage ratio levels; there was no such reduction based upon September 30, 2008 levels.

With respect to the TCEH Delayed Draw Term Loan Facility, a commitment fee is payable quarterly in arrears and upon termination of the undrawn portion of the commitments of such facility at a rate per annum equal to, prior to October 10, 2008, 1.25% per annum, and thereafter, 1.50% per annum.

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,

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less the issuing bank’s fronting fee. Letter of credit fees under the TCEH Letter of Credit Facility are equal to the difference between interest paid on each outstanding letter of credit at a rate of LIBOR plus 3.50% per annum and the interest earned on the total $1.25 billion TCEH Letter of Credit Facility restricted cash at a rate of LIBOR minus 0.12% per annum yielding a currently effective rate of 3.62% per annum on each outstanding letter of credit under that facility.

TCEH will pay a fixed quarterly maintenance fee of approximately $11 million through maturity for having procured the TCEH Commodity Collateral Posting Facility regardless of actual borrowings under the facility. In addition, TCEH will pay interest at LIBOR on actual borrowed amounts under the TCEH Commodity Collateral Posting Facility partially offset by interest earned on collateral deposits to counterparties.

The TCEH Senior Secured Facilities are unconditionally guaranteed jointly and severally on a senior secured basis, by EFC Holdings, and each existing and subsequently acquired or organized direct or indirect wholly-owned US restricted subsidiary of TCEH (other than certain subsidiaries as provided in the TCEH Senior Secured Facilities), subject to certain other exceptions.

The TCEH Senior Secured Facilities, including the guarantees thereof, certain commodity hedging transactions and the interest rate swaps described under “TCEH Interest Rate Hedges” below are secured by (a) substantially all of the current and future assets of TCEH and TCEH’s subsidiaries who are guarantors of such facilities as described above, and (b) pledges of the capital stock of TCEH and each current and future material wholly-owned restricted subsidiary of TCEH directly owned by TCEH or any guarantor.

The TCEH Senior Secured Facilities contain customary negative covenants, restricting, subject to certain exceptions, TCEH and TCEH’s restricted subsidiaries from, among other things:

• incurring additional debt;

• incurring additional liens;

• entering into mergers and consolidations;

• selling or otherwise disposing of assets;

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

• making acquisitions, investments, loans and advances, and

• paying or modifying certain subordinated and other material debt.

In addition, the TCEH Senior Secured Facilities contain a maintenance covenant that prohibits TCEH and its restricted subsidiaries from exceeding a maximum consolidated secured leverage ratio and to observe certain customary reporting requirements and other affirmative covenants.

The TCEH Initial Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of such facility ($41 million quarterly), with the balance payable on October 10, 2014. The TCEH Delayed Draw Term Loan Facility is required to be repaid in equal quarterly installments beginning on December 31, 2009 in an aggregate annual amount equal to 1% of the actual principal outstanding under the TCEH Delayed Draw Term Loan Facility as of such date, with the balance payable on October 10, 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time from and after the closing date until October 10, 2013. The TCEH Letter of Credit Facility will mature on October 10, 2014. The TCEH Commodity Collateral Posting Facility will mature on December 31, 2012.

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

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TCEH Notes Issued Subsequent to the Merger—Pursuant to an indenture entered into in October 2007 (the TCEH Indenture), TCEH and TCEH Finance (the Co-Issuers) issued and sold $3.0 billion aggregate principal amount of 10.25% Senior Notes due November 1, 2015. In December 2007 under a supplemental indenture, the Co-Issuers issued and sold $2.0 billion aggregate principal amount of 10.25% Series B Senior Notes due November 1, 2015. Interest on these notes (referred to as the TCEH Cash-Pay Notes) is payable in cash semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.25% per annum, and the first interest payment was made on May 1, 2008.

Pursuant to the supplemental indenture, the Co-Issuers also issued and sold $1.75 billion aggregate principal amount of 10.50%/11.25% Senior Toggle Notes due November 1, 2016. The initial interest payment on these notes (referred to as the TCEH Toggle Notes) was paid in cash. For any interest period thereafter until November 1, 2012, the Issuer may elect to pay interest on the notes, at the Issuer’s option (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new TCEH Toggle Notes (Payment-in-Kind or PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Interest on the notes is payable semi-annually in arrears on May 1 and November 1 of each year at a fixed rate of 10.50% per annum for cash interest and at a fixed rate of 11.25% per annum for PIK Interest, and the first interest payment was made on May 1, 2008.

The $6.75 billion principal amount of notes issued under the TCEH Indenture and its supplement (the TCEH Cash-Pay Notes and the TCEH Toggle Notes) are collectively referred to as the TCEH Notes.

The TCEH Notes are fully and unconditionally guaranteed by TCEH’s direct parent, EFC Holdings (which owns 100% of TCEH and its subsidiary guarantors), and by each subsidiary that guarantees the TCEH Senior Secured Facilities (the TCEH Guarantors). The TCEH Notes are the Co-Issuers’ senior unsecured debt and rank senior in right of payment to any future subordinated indebtedness of the Co-Issuers, equally in right of payment with all of the Co-Issuers’ existing and future senior unsecured indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities of the Co-Issuers’ non-guarantor subsidiaries, including trade payables (other than indebtedness and liabilities owed to the Co-Issuers or the TCEH Guarantors). The TCEH Notes rank effectively junior in right of payment to all existing and future senior secured indebtedness of the Co-Issuers, including the TCEH Senior Secured Facilities to the extent of the value of the collateral securing such indebtedness.

The guarantees are joint and several guarantees of the TCEH Notes, are the TCEH Guarantors’ senior unsecured obligations and rank equal in right of payment with all existing and future senior unsecured indebtedness of the relevant TCEH Guarantor and senior in right of payment to any existing or future subordinated indebtedness of the relevant TCEH Guarantor. The guarantees rank effectively junior to all secured indebtedness of the TCEH Guarantors to the extent of the assets securing that indebtedness. EFC Holdings’ guarantee of the TCEH Notes ranks equally with its guarantee of the EFH Corp. Cash-Pay Notes and the EFH Corp. Toggle Notes (discussed below). The guarantees of the TCEH Notes are structurally junior to all indebtedness and other liabilities of the Co-Issuers’ subsidiaries that do not guarantee the notes.

The TCEH Indenture contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Co-Issuers’ and their restricted subsidiaries’ ability to:

• make restricted payments;

• incur debt and issue preferred stock;

• create liens;

• enter into mergers or consolidations;

• sell or otherwise dispose of certain assets;

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

• engage in certain transactions with affiliates.

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The TCEH Indenture also contains customary events of default, including failure to pay principal or interest on the TCEH Notes or the guarantees when due, among others. If an event of default occurs under the TCEH Indenture, the trustee or the holders of at least 30% in principal amount of the Required Debt (as such term is defined in the TCEH Indenture) may declare the principal amount on the TCEH Notes to be due and payable immediately.

The Co-Issuers may redeem the TCEH Cash-Pay Notes, in whole or in part, at any time on or after November 1, 2011, or the TCEH Toggle Notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. In addition, before November 1, 2010, the Co-Issuers may redeem with the cash proceeds of certain equity offerings up to 35% of the aggregate principal amount of TCEH Cash-Pay Notes from time to time at a redemption price of 110.250% of the aggregate principal amount of the TCEH Cash-Pay Notes, plus accrued and unpaid interest, if any, or 110.500% of the aggregate principal amount of the TCEH Toggle Notes, plus accrued and unpaid interest, if any. The Co-Issuers may also redeem the TCEH Cash-Pay Notes at any time prior to November 1, 2011 or the TCEH Toggle Notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. Upon the occurrence of a change in control of TCEH, the Co-Issuers must offer to repurchase the TCEH Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

The TCEH Notes were issued in a private placement and have not been registered under 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 TCEH 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.

On September 26, 2008, EFC Holdings and TCEH filed a registration statement with the SEC to register notes to exchange for the TCEH Notes.

EFH Corp. Notes Issued Subsequent to the Merger—Pursuant to an indenture entered into in October 2007 (the EFH Corp. Indenture), EFH Corp. issued and sold $2.0 billion aggregate principal amount of 10.875% Senior Notes due November 1, 2017. Interest on the notes (referred to as the EFH Corp. Cash-Pay Notes) is payable in cash semi-annually in arrears on May 1 and November 1 of each year at a fixed rate of 10.875% per annum, and the first interest payment was made on May 1, 2008.

Pursuant to the EFH Corp. Indenture, EFH Corp. also issued and sold $2.5 billion aggregate principal amount of 11.250%/12.000% Senior Toggle Notes due November 1, 2017. The initial interest payment on the notes (referred to as the EFH Corp. Toggle Notes) was paid in cash. For any interest period thereafter until November 1, 2012, EFH Corp. may elect to pay interest on the notes, at EFH Corp.’s option (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFH Corp. Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Interest on the notes is payable semi-annually in arrears on May 1 and November 1 of each year at a fixed rate of 11.250% per annum for cash interest and at a fixed rate of 12.000% per annum for PIK Interest, and the first interest payment was made on May 1, 2008.

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.

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

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senior unsecured debt and rank senior in right of payment to any existing and future subordinated indebtedness of EFH Corp., equally in right of payment with all of EFH Corp.’s existing and future senior unsecured indebtedness and structurally subordinated in right of payment to all existing and future indebtedness, preferred stock and other liabilities of EFH Corp.’s non-guarantor subsidiaries, including trade payables (other than indebtedness and liabilities owed to EFH Corp. or the EFH Corp. Guarantors). The EFH Corp. Notes will rank effectively junior in right of payment to all future secured indebtedness of EFH Corp. to the extent of the assets securing that indebtedness.

The guarantees are joint and several guarantees of the EFH Corp. Notes, are the EFH Corp. Guarantors’ unsecured senior obligations and rank equal in right of payment with all existing and future senior unsecured indebtedness of the relevant EFH Corp. Guarantor and senior in right of payment to any existing or future subordinated indebtedness of the relevant EFH Corp. Guarantor. The guarantees of the EFH Corp. Notes will be structurally junior to all indebtedness and other liabilities of the relevant EFH Corp. Guarantor’s subsidiaries that are not guarantors.

The EFH Corp. Indenture contains a number of covenants that, among other things, restrict, subject to certain exceptions, EFH Corp.’s and its restricted subsidiaries’ ability to:

• make restricted payments;

• incur debt and issue preferred stock;

• create liens;

• enter into mergers or consolidations;

• sell or otherwise dispose of certain assets;

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

• engage in certain transactions with affiliates.

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

EFH Corp. may redeem the EFH Corp. Notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. In addition, before November 1, 2010, EFH Corp. may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the EFH Corp. Notes from time to time at a redemption price of 110.875% of the aggregate principal amount of the EFH Corp. Cash Pay Notes, plus accrued and unpaid interest, if any, or 111.250% of the aggregate principal amount of the EFH Corp. Toggle Notes, plus accrued and unpaid interest, if any. EFH Corp. may also redeem the EFH Corp. Notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. Upon the occurrence of a change in control, EFH Corp. must offer to repurchase the EFH Corp. Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

The EFH Corp. Notes were issued in a private placement 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

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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.

On September 17, 2008, EFH Corp. filed a registration statement with the SEC to register notes to exchange for the EFH Corp. Notes.

Intercreditor Agreement—In October 2007, in connection with the Merger, TCEH entered into an Intercreditor Agreement (the Intercreditor Agreement) with Citibank, N.A. and five secured commodity hedge counterparties (the Secured Commodity Hedge Counterparties). The Intercreditor Agreement provides that the lien granted to the Secured Commodity Hedge Counterparties will rank pari passu with the lien granted with respect to the collateral of the secured parties under the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will be entitled to share, on a pro rata basis, in the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateral in an amount provided in the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will have voting rights with respect to any amendment or waiver of any provision of the Intercreditor Agreement that changes the priority of the Secured Commodity Hedge Counterparties’ lien on such collateral relative to the priority of lien granted to the secured parties under the TCEH Senior Secured Facilities or the priority of payments to the Secured Commodity Hedge Counterparties upon a foreclosure and liquidation of such collateral relative to the priority of the lien granted to the secured parties under the TCEH Senior Secured Facilities.

TCEH Interest Rate Swap Transactions—In 2007, subsequent to the Merger, TCEH entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $15.05 billion of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.3% and 8.3% on debt maturing from 2009 to 2014. Prior to August 29, 2008, the interest rate swaps were being accounted for as cash flow hedges related to variable interest rate cash flows. As of August 29, 2008, these swaps were dedesignated as cash flow hedges as a result of the intent to change the variable interest rate terms of the hedged debt (from three-month LIBOR to one-month LIBOR) in connection with the planned execution of interest rate basis swaps (discussed immediately below) to further reduce the fixed borrowing costs. Based on the fair value of the positions, the cumulative unrealized mark-to-market net losses related to these interest rate swaps totaled $431 million (pre-tax) at August 29, 2008 and was recorded in accumulated other comprehensive income. This balance will be reclassified into net income as interest on the hedged debt is reflected in net income. No ineffectiveness gains or losses were recorded. After August 29, 2008, changes in the fair value of these swap transactions are being reported in the income statement in interest expense and related charges.

In September 2008, TCEH entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of an additional $1.5 billion of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.3% and 7.6% on debt maturing from 2013 to 2014. These swap transactions are also being marked-to-market in net income as interest expense and related charges. The interest rate swap counterparties are secured proportionally with the lenders under the TCEH Senior Secured Facilities.

In May 2008, TCEH entered into an interest rate swap transaction pursuant to which semiannual payment (settled quarterly) of the floating interest rates at LIBOR on an aggregate of $2.095 billion of senior secured term loans of TCEH were exchanged for floating interest rates of LIBOR plus 0.21% receivable monthly. In September 2008, TCEH entered into interest rate basis swap transactions pursuant to which quarterly payment of the floating interest rates at LIBOR on an aggregate of $7.95 billion of senior secured term loans of TCEH were exchanged for floating interest rates of LIBOR plus spreads ranging from 0.076% to 0.145% receivable monthly. The interest rate swap counterparties are secured proportionally with the lenders under the TCEH Senior Secured Facilities.

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As of September 30, 2008, all active interest rate swap transactions are being marked-to-market in net income. A total of $36 million in unrealized mark-to-market net gains related to interest rate swap transactions are included in interest expense and related charges for the quarter and year-to-date 2008 periods.

Oncor Revolving Credit Facility—At September 30, 2008, Oncor had a $2.0 billion credit facility to be used for working capital and general corporate purposes, including issuances of commercial paper and letters of credit. Oncor may request increases in the commitments under the facility in any amount up to $500 million, subject to the satisfaction of certain conditions. This facility is a revolving credit facility, which means that amounts borrowed under the facility, once repaid, can be reborrowed by Oncor from time to time until October 10, 2013. In May 2008, Oncor secured this credit facility with a first priority lien on certain of its transmission and distribution assets. Oncor also secured all of its existing long-term debt securities (excluding the transition bonds) with the same lien in accordance with the terms of those securities. The lien contains customary provisions allowing Oncor to use the assets in its business, as well as to replace and/or release collateral as long as the market value of the aggregate collateral is at least 115% of the aggregate secured debt. The lien may be terminated at Oncor’s option upon the termination of Oncor’s credit facility.

Borrowings under this credit facility totaled $150 million and $1.280 billion at September 30, 2008 and December 31, 2007, respectively. The decreased borrowings reflect the use of the majority of the proceeds from Oncor’s issuance of $1.5 billion of senior secured notes (discussed below) to repay borrowings under the revolving credit facility, partially offset by funding of ongoing capital investments, including the acquisition of CURRENT Communications of Texas, LP’s existing broadband over powerline based “Smart Grid” network assets in Oncor’s service territory.

Borrowings under this credit facility bear interest at per annum rates equal to, at Oncor’s option, (i) adjusted LIBOR plus a spread of 0.275% to 0.800% (depending on the rating assigned to Oncor’s senior secured debt) or (ii) a base rate (the higher of (1) the prime rate of JPMorgan Chase Bank, N.A. and (2) the federal funds effective rate plus 0.50%). Under option (i) and based on Oncor’s current ratings, its LIBOR-based borrowings, which apply to all outstanding borrowings at September 30, 2008, bear interest at LIBOR plus 0.425%.

A facility fee is payable at a rate per annum equal to 0.100% to 0.200% (depending on the rating assigned to Oncor’s senior secured debt) of the commitments under the facility. Based on Oncor’s current ratings, its facility fee is 0.150%. A utilization fee is payable on the average daily amount of borrowings in excess of 50% of the commitments under the facility at a rate per annum equal to 0.125% per annum.

The credit facility contains customary covenants for facilities of this type, restricting, subject to certain exceptions, Oncor and its subsidiary from, among other things:

• incurring additional liens;

• entering into mergers and consolidations;

• selling certain assets, and

• making acquisitions and investments in subsidiaries.

In addition, the credit facility requires that Oncor maintain a consolidated senior debt to capitalization ratio of no greater than 0.65 to 1.00 and observe certain customary reporting requirements and other affirmative covenants.

The credit facility contains certain customary events of default for facilities of this type, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments under the facility.

Oncor Senior Secured Notes—Pursuant to an indenture dated as of August 1, 2002, in September 2008, Oncor issued and sold senior secured notes with an aggregate principal amount of $1.500 billion consisting of

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$650 million aggregate principal amount of 5.95% senior secured notes maturing in September 2013, $550 million aggregate principal amount of 6.80% senior secured notes maturing in September 2018 and $300 million aggregate principal amount of 7.50% senior secured notes maturing in September 2038. Oncor used the proceeds of approximately $1.487 billion from the sale of the Oncor notes to repay most of its borrowings under its credit facility as well as for general corporate purposes. The Oncor notes will initially be secured by the first priority lien described above. If the lien is terminated, the notes will cease to be secured obligations of Oncor and will become senior unsecured general obligations of Oncor.

Interest on these notes is payable in cash semiannually in arrears on March 1 and September 1 of each year, and the first interest payment is due on March 1, 2009. Oncor may redeem the notes, in whole or in part, at any time, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. The Oncor notes also contain customary events of default, including failure to pay principal or interest on the notes when due.

The Oncor notes were issued in a private placement and have not been registered under the Securities Act. Oncor has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the Oncor notes as part of an offer to exchange freely tradable exchange notes for the Oncor notes. Oncor has agreed to use commercially reasonable efforts to cause the exchange offer to be completed or, if required, to have one or more shelf registration statements declared effective, within 270 days after the issue date of the Oncor notes. If this obligation is not satisfied (an Oncor Registration Default), the annual interest rate on the Oncor notes will increase by 0.50% per annum over the applicable original interest rate until the earlier of the expiration of the Oncor Registration Default period or the second anniversary of the issue date of the notes. Oncor also agreed to file a registration statement containing a “market making prospectus” and to keep it effective, subject to certain exceptions, for a period of ten years after the issue date of the Oncor notes.

Oncor Interest Rate Hedges—In September 2008, Oncor entered into interest rate swap transactions hedging the variability of treasury bond rates used to determine the interest rates on an anticipated issuance of an aggregate of $1.0 billion of senior secured notes maturing from 2013 to 2018. The hedges were terminated the same day, and $2 million in after-tax losses were recorded as other comprehensive income. Oncor expects that $0.4 million of after-tax net losses will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

8. COMMITMENTS AND CONTINGENCIES

Generation Development

Subsidiaries of EFH Corp. have executed EPC agreements for the development of three lignite-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 litigation as discussed below under “Litigation Related to Generation Development.”

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 litigation as discussed below under “Litigation Related to Generation Development.”

Construction work-in-process asset balances for the three generation units totaled approximately $3.75 billion as of September 30, 2008, which includes the effects of the fair value adjustments related to purchase accounting and capitalized interest. If construction-related agreements for the three generation units had been cancelled as of that date, subsidiaries of EFH Corp. would have incurred an estimated termination obligation of

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up to approximately $350 million. This estimated gross cancellation exposure of approximately $4.10 billion at September 30, 2008 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.

Litigation Related to the Merger

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

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

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

In July 2007, a putative class action lawsuit was filed in the US District Court, Northern District of Texas, Dallas Division by a putative shareholder against EFH Corp. (then known as TXU Corp.) and its former directors asserting a claim under Section 14(a) of the Securities Exchange Act of 1934 and the rules and regulations thereunder, asserting that the preliminary proxy statement of EFH Corp. filed in June 2007 failed to adequately describe the relevant facts and circumstances regarding the Merger as well as seeking to certify the litigation as a

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class action on behalf of allegedly similarly situated shareholders. In July 2007, the Sponsor Group, joined by EFH Corp. entered into a memorandum of understanding with plaintiffs that resulted in the dismissal of this litigation as described below.

In July 2007, the Sponsor Group, joined by EFH Corp. for the limited purpose described below, executed a memorandum of understanding with the plaintiffs in certain of the lawsuits described above pursuant to which, when approved by the court in which the litigation was pending, to the extent required, all of the litigation related to the Merger described above would 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 related to the approval of the Merger as part of the agreement between the Sponsor Group and the plaintiffs to settle the litigation and agreed that under certain circumstances the termination fee payable by EFH Corp. under the Merger Agreement would be $925 million rather than $1 billion. In addition, by reasons of the closing of the Merger on October 10, 2007, EFH Corp. merged with the entity obligated to fund any court approved attorneys’ fees. Accordingly, EFH Corp. was legally obligated for such payment. In January 2008, a final settlement agreement was executed by the Plaintiffs in the above described litigation matters. The defendants and the courts with jurisdiction over the litigation considered the settlement for approval in April 2008. The settlement was approved and a Final Order and Judgment was entered dismissing with prejudice all litigation pending in the State District Court, Dallas County, Texas. The settlement was approved and a Final Order and Judgment was entered into by the US District Court in May 2008, dismissing with prejudice all claims related to the Merger against EFH Corp. and its preclosing officers and directors. In June 2008, an objector appealed the Final Order and Judgment of the US District Court to the US Court of Appeals for the Fifth Circuit. EFH Corp. believes the claims made in the appeal are without merit; therefore, if necessary, EFH Corp. intends to vigorously defend this appeal.

Litigation Related to Generation Development

An administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas to a subsidiary of EFH Corp. was filed in September 2007 in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse TCEQ’s approval of the Oak Grove air permit and TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments; and remand the matter back to TCEQ for further proceedings. The TCEQ has filed the administrative record with the District Court. No further activity has occurred in the appeal. 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 filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. EFH Corp. believes the Oak Grove air permit granted by the TCEQ is protective of the environment and that the application for and the processing of the air permit by the TCEQ was in accordance with law. There can be no assurance that the outcome of these matters would not result in an adverse impact on the Oak Grove project.

In December 2006, a lawsuit was filed in the US District Court for the Western District of Texas against Luminant Generation Company LLC (then known as TXU Generation Company LP), Oak Grove Management Company LLC (both indirect wholly-owned subsidiaries of EFH Corp.) and EFH Corp. (then known as TXU Corp.). The complaint sought declaratory and injunctive relief, as well as the assessment of civil penalties, with respect to the permit application for the construction and operation of the Oak Grove generation facility in Robertson County, Texas. The plaintiffs alleged violations of the Federal Clean Air Act, Texas Health and Safety Code and Texas Administrative Code and sought to temporarily and permanently enjoin the construction and operation of the Oak Grove generation plant. The complaint also asserted that the permit application was deficient in failing to comply with various modeling and analyses requirements relative to the impact of emissions from the Oak Grove plant. Plaintiffs further requested that the District Court enter an order requiring

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the defendants to take other appropriate actions to remedy, mitigate and offset alleged harm to the public health and environment. EFH Corp. believes the Oak Grove air permit granted by the TCEQ in June 2007 is protective of the environment and that the application for and the processing of the air permit by Oak Grove Management Company LLC with the TCEQ has been in accordance with applicable law. EFH Corp. and the other defendants filed a Motion to Dismiss the litigation, which was granted by the District Court in May 2007. The plaintiffs appealed the District Court’s dismissal of the case to the US Fifth Circuit Court of Appeals, and in July 2008, the US Fifth Circuit Court of Appeals upheld the District Court’s dismissal of the case. The plaintiffs have appealed that decision by the US Fifth Circuit Court of Appeals to the US Supreme Court. EFH Corp. believes that the US Fifth Circuit Court of Appeals properly upheld the District Court’s decision and will continue to defend that decision because EFH Corp. believes that the claims made by the plaintiffs are without merit. EFH Corp. is unable to estimate any possible loss or predict the outcome of this litigation. There can be no assurance that the outcome of this matter would not result in an adverse impact on the Oak Grove project.

In May 2008, the Sierra Club announced that it may sue Oak Grove Management Company LLC for violating federal Clean Air Act provisions regarding hazardous air pollutants. Similarly, in July 2008, the Sierra Club announced that it may sue Luminant, after the expiration of a 60-day waiting period, for violating federal Clean Air Act provisions in connection with its Martin Lake generation facility. EFH Corp. believes that, contrary to Sierra Club’s allegations, it obtained lawful permits for constructing the Oak Grove generation facility and that it is in compliance with emissions requirements applicable to the Martin Lake generation facility. EFH Corp. cannot predict whether the Sierra Club will actually file suit or the outcome of any such proceedings.

In September 2007, a subsidiary of EFH Corp. acquired from Alcoa Inc. the air permit related to the Sandow 5 facility that had been previously issued by the TCEQ. Although a federal district court approved a settlement pursuant to which EFH Corp. acquired the permit, environmental groups opposed to the settlement appealed the district court’s decision to the US Fifth Circuit Court of Appeals. In June 2008, the US Fifth Circuit Court of Appeals upheld the district court’s decision. EFH Corp. believes the claims are without merit and will vigorously defend any further appeal. There can be no assurance that the outcome of this matter would not result in an adverse impact on the Sandow 5 project or EFH Corp.

Litigation-Other

In September 2005, a lawsuit was filed in the US District Court for the Northern District of Texas, Dallas Division against EFH Corp. (then known as TXU Corp.) and C. John Wilder, EFH Corp.’s former Chief Executive Officer. The plaintiffs’ Amended Complaint asserts claims on behalf of the plaintiffs and a putative class of owners of certain EFH Corp. securities who tendered such securities in connection with a tender offer conducted by EFH Corp. in 2004. The Amended Complaint alleges violations of the provisions of Sections 14(e), 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 thereunder. The allegations relate to a tender offer conducted in September and October 2004 for certain equity-linked securities in which it was expressly disclosed that EFH Corp. management was evaluating whether it should recommend to the board of directors that the board reevaluate EFH Corp.’s dividend policy. After the tender offer was closed, and consistent with the disclosure, management did make a recommendation to the board to reevaluate the dividend policy, and the board elected to increase the quarterly dividend. The plaintiffs contend that such disclosure in connection with the tender offer was inadequate. EFH Corp. maintains that the disclosure provided in connection with the tender offer regarding the evaluation of the dividend policy was complete and accurate at the time the tender offer was initiated as well as when it was closed. A Motion to Dismiss was filed by the defendants, and the District Court entered an order granting the Motion to Dismiss and dismissing this litigation with prejudice in August 2006. The plaintiffs filed a timely notice of appeal, and on appeal, the US Court of Appeals for the Fifth Circuit remanded the dismissal to the District Court in light of the decisions in Tellabs, Inc. v. Makor Issues & Rights, Ltd. On remand, plaintiffs filed a Second Amended Complaint, and defendants filed a Motion to Dismiss. The District Court entered an order granting the Motion to Dismiss and dismissing this litigation with prejudice in April 2008. The plaintiffs filed a timely notice of appeal in May 2008 and the appeal is currently pending before the US Court of Appeals for the Fifth Circuit. Briefing on the appeal has been completed. While EFH

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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.

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

Regulatory Investigations and Reviews

In March 2007, the PUCT issued a Notice of Violation (NOV) stating that the PUCT Staff was recommending an enforcement action, including the assessment of administrative penalties, against EFH Corp. and certain affiliates for alleged market power abuse by its power generation affiliates and Luminant Energy in ERCOT-administered balancing energy auctions during certain periods of the summer of 2005. In September 2007, the PUCT issued a revised NOV in which the proposed administrative penalty amount was reduced from $210 million to $171 million. The revised NOV was necessary, according to the PUCT Staff, to correct calculation errors in the initial NOV. As revised, the NOV 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. In March 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. In April 2008, PUCT Staff submitted its cross-motion on the same issue. In July 2008, the administrative law judges issued their order on the cross-motions for summary decision. The order held that the PUCT Staff’s proposed penalty calculation is unlawful and ruled partially in Luminant Energy’s favor, holding that the proper maximum penalty calculation should be based on the number of allegedly improper bid curves submitted to ERCOT during the relevant time period. The order also holds that a fact issue exists with respect to the number of bid curves submitted during the relevant period. Based upon this order and the PUCT Staff’s alleged number of bid curves, EFH Corp. believes that the maximum penalty would have been less than $16 million. The PUCT Staff appealed the administrative law judges’ ruling on this maximum penalty issue to the PUCT, and at the August 14, 2008 PUCT open meeting, the PUCT Commissioners determined that it was inappropriate to decide the issue of how to calculate the potential maximum penalty at this point in the case. Instead, the PUCT indicated that the maximum penalty issue should be determined as part of the final resolution of the entire proceeding, after a full hearing on the merits. 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. However, in the interest of potentially resolving this matter in an expeditious manner, the NOV proceeding is currently abated while the PUCT Staff and Luminant Energy engage in settlement discussions. If the proceeding is not resolved through settlement, EFH Corp. will continue to vigorously contest the NOV. EFH Corp. is unable to predict the outcome of this matter.

In June 2008, the EPA issued a request for information to Luminant Energy under EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by

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the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. EFH Corp. is cooperating with the EPA and is responding in good faith to the EPA’s request. EFH Corp. is unable to predict the outcome of this matter.

Other Proceedings

In addition to the above, EFH Corp. 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.

Guarantees

As discussed below, EFH Corp. and its subsidiaries have entered into contracts that contain guarantees to outside parties that could require performance or payment under certain conditions.

Disposed TXU Gas operations—In connection with the TXU Gas transaction in October 2004, EFH Corp. agreed to indemnify Atmos Energy Corporation (Atmos), until October 1, 2014, for up to $500 million for any liability related to assets retained by TXU Gas, including certain inactive gas plant sites not acquired by Atmos 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 under any of these indemnity obligations, and no such payments are currently anticipated.

Residual value guarantees in operating leases—EFH Corp. or a subsidiary is the lessee under various operating leases that guarantee the residual values of the leased assets. At September 30, 2008, the aggregate maximum amount of residual values guaranteed was approximately $69 million with an estimated residual recovery of approximately $75 million. These leased assets consist primarily of mining equipment, rail cars and vehicles. The average life of the lease portfolio is approximately four years.

Indebtedness guarantee—In 1990, EFC Holdings repurchased an electric co-op’s minority ownership interest in the Comanche Peak nuclear generation plant and assumed the co-op’s indebtedness to the US government for the facilities. The indebtedness is included in long-term debt reported in the consolidated balance sheet. EFC Holdings is making principal and interest payments to the co-op in an amount sufficient for the co-op to make payments on its indebtedness. EFC Holdings guaranteed the co-op’s payments, and in the event that the co-op fails to make its payments on the indebtedness, the US government would assume the co-op’s rights under the agreement, and such payments would then be owed directly by EFC Holdings. At September 30, 2008, the balance of the indebtedness was $112 million with maturities of principal and interest extending to December 2021. The indebtedness is secured by a lien on the purchased facilities.

See Note 7 for discussion of guarantees and security for certain EFH Corp. indebtedness.

Letters of Credit

At September 30, 2008, TCEH had outstanding letters of credit under its credit facilities totaling $1.233 billion as follows:

• $829 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions;

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

• $121 million to support obligations under the lease agreement for an EFH Corp. office building, and

• $75 million for miscellaneous credit support requirements.

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Nuclear Insurance

As a result of the US Terrorism Risk Insurance Program Reauthorization Act of 2007 that was effective January 1, 2008, under the American Nuclear Insurers liability policy, the liability arising out of terrorist acts that was previously subject to one industry aggregate limit of $300 million is no longer subject to an aggregate limit.

9. SHAREHOLDERS’ EQUITY

Equity Contributions

In the nine months ended September 30, 2008, EFH Corp. issued an aggregate of approximately 5.3 million shares of its common stock to, or for the benefit of, certain of its officers, directors and employees for an aggregate consideration of approximately $26 million, which includes shares previously subscribed.

Dividend Restrictions

The indenture governing the EFH Corp. Senior Cash-Pay and Toggle Notes includes covenants that, among other things and subject to certain exceptions, restrict EFH Corp.’s ability to pay dividends or make other distributions in respect of its capital stock. Accordingly, essentially all of EFH Corp.’s net income is restricted from being used to make distributions on its common stock unless such distributions are expressly permitted under the indenture and/or after such distributions, on a pro forma basis, after giving effect to such payment, the consolidated leverage ratio of EFH Corp. is equal to or less than 7.0 to 1.0. Consolidated leverage ratio is generally defined as the ratio of consolidated total indebtedness (as defined in the indenture) of EFH Corp. to Adjusted EBITDA of EFH Corp., in each case, on a consolidated basis, excluding Oncor Holdings and its subsidiaries. In addition, the TCEH Senior Secured Facilities generally restrict TCEH from making any distribution to any of its parent companies for the ultimate purpose of making a distribution to Texas Holdings unless at the time, and after giving effect to such distribution, TCEH’s consolidated total debt (as defined in the TCEH Senior Secured Facilities) to TCEH’s Adjusted EBITDA would be equal to or less than 6.5 to 1.0.

Shareholders’ Equity

The following table presents the changes to shareholders’ equity during the nine months ended September 30, 2008.

	Common Stock		Additional Paid-in Capital		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
Balance at December 31, 2007	$	—	$	8,279	$	(1,360	)	$	(234	)	$	6,685
Net loss		—		—		(983	)		—			(983	)
Effects of employee stock-related activities		—		29		—			—			29
Net effects of cash flow hedges		—		—		—			(100	)		(100	)
Other		—		1		—			1			2
Balance at September 30, 2008	$	—	$	8,309	$	(2,343	)	$	(333	)	$	5,633

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10. 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 September 30, 2008
	Commodity contracts			Other derivatives			Reclassification (a)			Total—Balance Sheet amount
Assets:
Current assets	$	1,531		$	34		$	(10	)	$	1,555
Noncurrent assets		325			15			—			340
Total	$	1,856		$	49		$	(10	)	$	1,895
Liabilities:
Current liabilities	$	1,784		$	232		$	(10	)	$	2,006
Noncurrent liabilities		2,213			243			—			2,456
Total	$	3,997		$	475		$	(10	)	$	4,462
Net assets (liabilities)	$	(2,141	)	$	(426	)	$	—		$	(2,567	)

(a) Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities.

	Successor December 31, 2007
	Commodity contracts			Other derivatives			Total—Balance Sheet amount
Assets:
Current assets	$	1,118		$	11		$	1,129
Noncurrent assets		239			5			244
Total	$	1,357		$	16		$	1,373
Liabilities:
Current liabilities	$	1,042		$	104		$	1,146
Noncurrent liabilities		2,232			221			2,453
Total	$	3,274		$	325		$	3,599
Net assets (liabilities)	$	(1,917	)	$	(309	)	$	(2,226	)

Margin deposits net assets of $618 million and $445 million under master netting arrangements at September 30, 2008 and December 31, 2007, respectively, were not netted with derivative assets and liabilities since EFH Corp. has elected to present the amounts of derivative assets and liabilities on a gross basis in the balance sheet as provided in FIN 39-1. See discussion in Note 1 under “Changes in Accounting Standards.”

This presentation can result in significant volatility in commodity contract assets and liabilities because EFH Corp. enters into positions with the same counterparties that result in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.

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 and reported in the income statement in net losses from commodity hedging and trading activities.

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Results for the three months ended September 30, 2008 and 2007 include net “day one” losses of $10 million and $58 million, respectively. Results for the nine months ended September 30, 2008 and 2007 include net “day one” losses of $68 million and $192 million, respectively, primarily associated with commodity contracts entered into at below market prices. Substantially all of these amounts represent losses associated with related series of transactions involving natural gas financial instruments intended to hedge exposure to future changes in electricity prices. The year-to-date 2007 amount also includes a $30 million “day one” gain associated with a long-term power purchase agreement entered into in the second quarter of 2007. The net losses are reported in the income statement in net gain (loss) from commodity hedging and trading activities, consistent with other mark-to-market hedging and trading gains and losses, and are included in the results of the Competitive Electric segment.

Other Derivative Assets and Liabilities

Other derivative assets and liabilities primarily represent fair values of interest rate swaps and also include fair values of commodity contracts that have been designated as cash flow hedges.

A significant portion of natural gas derivatives entered into to hedge future changes in electricity prices had previously been designated and accounted for as cash flow hedges. In March 2007, these instruments were dedesignated as cash flow hedges as allowed under SFAS 133, thus becoming subject to mark-to-market accounting in net income as the fair values change. See Note 7 for details of interest rate swaps previously designated as cash flow hedges.

A summary of transactions comprising other derivative assets and liabilities follows:

	Successor
	September 30, 2008		December 31, 2007
Current and noncurrent assets:
Interest rate swaps (a)	$	35	$	8
Commodity-related cash flow hedges		14		8
Total	$	49	$	16
Current and noncurrent liabilities:
Interest rate swaps (a)	$	464	$	324
Commodity-related cash flow hedges		11		1
Total	$	475	$	325

(a) September 30, 2008 amount includes $404 million in net liabilities related to interest rate hedges on $16.55 billion principal amount of debt and $8 million in net assets related to interest rate basis swaps on $10.045 billion principal amount of debt, both entered into after the Merger, and $33 million in net liabilities related to swaps existing at the time of the Merger. As of August 29, 2008, changes in fair value of these swaps are marked-to-market in net income.

Other Cash Flow Hedge Information—EFH Corp. experienced cash flow hedge ineffectiveness of zero and $4 million in net losses for the three and nine month periods ended September 30, 2008, respectively. For the corresponding periods of 2007, the amounts were $1 million in net losses and $111 million in net gains, respectively. These amounts are pretax and are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

The net effect of recording unrealized mark-to-market gains and losses arising from hedge ineffectiveness (versus recording gains and losses upon settlement) includes the above amounts as well as the effect of reversing unrealized ineffectiveness gains and losses recorded in previous periods to offset realized gains and losses in the current period. Such net unrealized effect totaled zero and $4 million in net losses for the three and nine month

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periods ended September 30, 2008, respectively, and $2 million in net losses and $92 million in net gains for the three and nine month periods ended September 30, 2007, respectively.

Accumulated other comprehensive income related to cash flow hedges at September 30, 2008 totaled $278 million in net losses (after-tax), substantially all of which relates to interest rate swaps. EFH Corp. expects that $120 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of September 30, 2008 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

11. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) COSTS

Net pension and OPEB costs for the three and nine months ended September 30, 2008 and 2007 are comprised of the following:

	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Components of net pension costs:
Service cost	$	12		$	10		$	29		$	30
Interest cost		51			36			117			107
Expected return on assets		(56	)		(39	)		(133	)		(118	)
Prior service cost		—			—			1			1
Net loss		—			5			—			15
Net pension cost		7			12			14			35
Components of net OPEB costs:
Service cost		3			3			8			9
Interest cost		14			14			44			41
Expected return on assets		(5	)		(5	)		(15	)		(15	)
Net transition obligation		—			—			—			1
Prior service cost		—			—			(1	)		(2	)
Net loss		2			3			8			16
Net OPEB cost		14			15			44			50
Net pension and OPEB costs		21			27			58			85
Less amounts deferred principally as a regulatory asset or property		(10	)		(15	)		(32	)		(44	)
Net amounts recognized as expense	$	11		$	12		$	26		$	41

The discount rate reflected in net pension and OPEB costs in 2008 is 6.55%. The expected rate of return on plan assets reflected in the 2008 cost amounts is 8.25% for the pension plan and 7.90% for the OPEB plan.

In 2008, EFH Corp. will not record any amortization of the estimated net loss and prior service cost for the defined benefit pension plans as well as 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. eliminating accumulated other comprehensive income as a result of purchase accounting for the Merger, and as a result, being within the SFAS 158 guidelines under which amortization of accumulated other comprehensive income is not required until the accumulated other comprehensive income balance exceeds 10% of the benefit obligation.

EFH Corp. made required pension contributions of $7 million, $18 million and $113 million in the first, second and third quarters of 2008, respectively. EFH Corp. expects to make required contributions of $22 million to its pension plan in the fourth quarter of 2008.

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12. 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 an observable market price. Additionally, SFAS 157 requires an entity to take its own credit risk (nonperformance risk) into consideration when measuring the fair value of liabilities. EFH Corp. adopted SFAS 157 effective with the closing of the Merger. 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 transacted through clearing brokers for which the pricing is actively quoted.

• Level 2 valuations use inputs other than actively quoted market prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other means. EFH Corp.’s Level 2 assets and liabilities utilize over the counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means and other valuation inputs. For example, EFH Corp.’s Level 2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes are available.

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

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EFH Corp. utilizes several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.

In utilizing broker quotes, EFH Corp. attempts to obtain multiple quotes from brokers that are active in the commodity markets in which it participates (and requires at least two quotes to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes that EFH Corp. receives for certain pricing inputs varies depending on the depth of the trading market, each individual broker’s publication policy, recent trading volume shifts and various other factors. Broker quotes received are generally binding where markets are actively traded. In addition, for valuation of interest rate hedges, EFH Corp. uses a combination of dealer provided market valuations (generally non-binding) and Bloomberg valuations based on month-end interest rate curves and standard rate swap valuation models.

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

With respect to amounts presented in the following fair value hierarchy table, the fair value measurement of an asset or liability (e.g. a contract) is required under SFAS 157 to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.

At September 30, 2008, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Successor
	Level 1		Level 2		Level 3		Reclassification (a)		Total
Assets:
Commodity-related contracts	$	587	$	1,005	$	177	$	91	$	1,860
Interest rate swaps		—		35		—		—		35
Nuclear decommissioning trust (b)		135		299		—		—		434
Salary deferral plan investments (b)		10		62		—		—		72
Total assets	$	732	$	1,401	$	177	$	91	$	2,401
Liabilities:
Commodity-related contracts	$	865	$	2,673	$	369	$	91	$	3,998
Interest rate swaps		—		464		—		—		464
Total liabilities	$	865	$	3,137	$	369	$	91	$	4,462

(a) Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities.

(b) EFH Corp.’s nuclear decommissioning trust and salary deferral plan investments are included in the Investments line on the balance sheet.

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Commodity-related contracts consist primarily of natural gas and electricity derivative instruments entered into for hedging purposes and include physical contracts that have not been designated “normal” purchases or sales under SFAS 133.

Interest rate swaps consist largely of variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of EFH Corp.’s nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

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.

The following table presents the changes in fair value of EFH Corp.’s Level 3 assets and liabilities (all related to commodity contracts) for the three and nine months ended September 30, 2008:

	Three Months Ended September 30, 2008			Nine Months Ended September 30, 2008
Balance at beginning of period (net liability)	$	(539	)	$	(173	)
Total realized and unrealized gains (losses) (a):
Included in net income (loss)		395			(82	)
Included in other comprehensive income		(8	)		7
Purchases, sales, issuances and settlements (net) (b)		(31	)		49
Net transfers in and/or out of Level 3 (c)		(9	)		7
Balance at September 30, 2008 (net liability)	$	(192	)	$	(192	)
Net change in unrealized gains (losses) included in net income relating to instruments held at September 30, 2008 (a)	$	435		$	10

(a) Substantially all changes in values of commodity-related contracts are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

(b) Purchases, sales and issuances represent amounts for new transactions entered into during the period and any unrealized gains (losses) that occurred during the period for those transactions. Settlements represent amounts included in the beginning balance for the period. Amount also includes fair values of transactions with Lehman Brothers Holdings Inc. that were terminated and therefore were reclassified from commodity and other derivative contractual assets to accounts receivable, which was reserved for as a charge reported in other deductions (see Notes 5 and 6).

(c) Includes transfers due to changes in the observability of significant inputs. Amounts transferred in and/or out represent September 30, 2008 values.

13. RELATED PARTY TRANSACTIONS

In the three and nine months ended September 30, 2008, EFH Corp. accrued $9 million and $26 million, respectively, of an annual management fee of $35 million under terms of a Management Agreement with the Sponsor Group. The fee is reported as SG&A expense in Corporate and Other activities.

At the closing of the Merger, TCEH entered into the TCEH Senior Secured Facilities and Oncor entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of GS Capital Partners have from time to time engaged in commercial banking and financial advisory transactions with EFH Corp. or its subsidiaries in the normal course of business.

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Affiliates of Goldman Sachs & Co. are party to certain commodity and interest rate hedging transactions with EFH Corp. or its subsidiaries in the normal course of business.

From time to time affiliates of the Sponsor Group may acquire debt or debt securities issued by EFH Corp. or its subsidiaries in open market transactions or through loan syndications.

14. SEGMENT INFORMATION

EFH Corp.’s operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.

The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, the development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales to residential and business customers, all largely in Texas. These activities are conducted principally by subsidiaries of TCEH. The results of this segment also include equipment salvage and resale activities related to the eight cancelled coal-fueled generation units.

The Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly owned bankruptcy-remote financing subsidiary, and also include certain revenues and costs associated with installation of equipment that will facilitate Oncor’s technology initiatives.

Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued operations, general corporate expenses and interest on EFH Corp. and EFC Holdings debt.

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The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 in the 2007 Form 10-K. 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.

	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Operating revenues:
Competitive Electric	$	3,258		$	2,572		$	7,809		$	6,624
Regulated Delivery		728			712			1,969			1,919
Corporate and Other		10			13			27			35
Eliminations		(301	)		(314	)		(804	)		(835	)
Consolidated	$	3,695		$	2,983		$	9,001		$	7,743
Regulated revenues included in operating revenues:
Competitive Electric	$	—		$	—		$	—		$	—
Regulated Delivery		728			712			1,969			1,919
Corporate and Other		—			—			—			—
Eliminations		(290	)		(300	)		(775	)		(797	)
Consolidated	$	438		$	412		$	1,194		$	1,122
Affiliated revenues included in operating revenues:
Competitive Electric	$	2		$	3		$	5		$	5
Regulated Delivery		290			300			775			797
Corporate and Other		9			11			24			33
Eliminations		(301	)		(314	)		(804	)		(835	)
Consolidated	$	—		$	—		$	—		$	—
Income (loss) from continuing operations:
Competitive Electric	$	3,611		$	948		$	(862	)	$	609
Regulated Delivery		139			124			309			264
Corporate and Other		(133	)		(93	)		(430	)		(282	)
Consolidated	$	3,617		$	979		$	(983	)	$	591

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15. SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations

	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Operating revenues
Regulated	$	728		$	712		$	1,969		$	1,919
Unregulated		3,268			2,585			7,836			6,659
Intercompany sales eliminations—regulated		(290	)		(300	)		(775	)		(797	)
Intercompany sales eliminations—unregulated		(11	)		(14	)		(29	)		(38	)
Total operating revenues		3,695			2,983			9,001			7,743
Fuel, purchased power and delivery fees—unregulated (a)		(1,631	)		(882	)		(3,867	)		(2,286	)
Net gain (loss) from commodity hedging and trading activities		6,045			462			(248	)		(607	)
Operating costs—regulated		(213	)		(214	)		(620	)		(616	)
Operating costs—unregulated		(157	)		(136	)		(500	)		(449	)
Depreciation and amortization—regulated		(128	)		(119	)		(370	)		(353	)
Depreciation and amortization—unregulated		(303	)		(90	)		(847	)		(259	)
Selling, general and administrative expenses—regulated		(42	)		(43	)		(126	)		(131	)
Selling, general and administrative expenses—unregulated		(207	)		(186	)		(586	)		(543	)
Franchise and revenue-based taxes—regulated		(67	)		(69	)		(186	)		(190	)
Franchise and revenue-based taxes—unregulated		(25	)		(24	)		(73	)		(79	)
Other income		14			20			43			65
Other deductions		(541	)		(10	)		(583	)		(901	)
Interest income		9			19			22			53
Interest expense and other charges		(831	)		(226	)		(2,505	)		(644	)
Income (loss) from continuing operations before income taxes	$	5,618		$	1,485		$	(1,445	)	$	803

(a) Includes unregulated cost of fuel consumed of $538 million and $358 million for the three months ended September 30, 2008 and 2007, respectively, and $1.320 billion and $835 million for the nine months ended September 30, 2008 and 2007, respectively. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.

Stock-Based Compensation

Under the terms of the EFH Corp. 2007 Stock Incentive Plan, options to purchase 4.5 million and 29.4 million shares of EFH Corp. common stock were issued to certain EFH Corp. management employees, directors and consultants in the three and nine months ended September 30, 2008, respectively. Vested awards must be exercised within 10 years of the grant date. The terms of the options were fixed at grant date. Options to purchase 1 million and 3 million shares were forfeited during the three and nine months ended September 30, 2008, respectively.

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In addition, zero and 860,000 restricted shares of EFH Corp. common stock were granted in the three and nine months ended September 30, 2008, respectively, and 14,000 and 454,000 shares of EFH Corp. common stock were awarded as compensation in the three and nine months ended September 30, 2008, respectively, to EFH Corp. management employees and directors. Regarding restricted shares, 32,500 and 97,500 vested in the three and nine months ended September 30, 2008, respectively.

Expenses recognized for options granted totaled $8 million and $15 million for the three and nine month periods ended September 30, 2008, respectively. Expenses recognized for share awards (restricted and unrestricted) totaled $5 million and $11 million for the three and nine months ended September 30, 2008, respectively.

Interest Expense and Related Charges

	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Interest	$	877		$	249		$	2,600		$	701
Amortization of fair value debt discounts resulting from purchase accounting		18			—			55			—
Amortization of debt issuance costs and discounts		48			6			111			18
Unrealized mark-to-market net gain on interest rate swaps		(36	)		—			(36	)		—
Capitalized interest, primarily related to generation facility and regulated utility asset construction		(76	)		(29	)		(225	)		(75	)
Total interest expense and related charges	$	831		$	226		$	2,505		$	644

Restricted Cash

	Successor
	At September 30, 2008				At December 31, 2007
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to TCEH’s Letter of Credit Facility (See Note 7)	$	—	$	1,250	$	—	$	1,250
Amounts related to margin deposits held		20		—		—		—
Pollution control revenue bond funds held by trustee (See Note 7)		—		—		—		29
Amounts related to securitization (transition) bonds		64		17		56		17
Total restricted cash	$	84	$	1,267	$	56	$	1,296

Inventories by Major Category

	Successor
	September 30, 2008		December 31, 2007
Materials and supplies	$	203	$	174
Fuel stock		144		138
Natural gas in storage		65		93
Total inventories	$	412	$	405

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Investments Held in Money Market Fund

As of September 30, 2008, EFH Corp. held a $242 million interest in The Reserve’s US Government Fund, which began liquidation proceedings in September 2008 due to the credit crisis and withdrawal demands. In September 2008, EFH Corp. attempted to redeem its interest in the US Government Fund, but due to the liquidation process, the funds were not immediately made available. EFH Corp. expects to receive its funds by the end of the fourth quarter.

Investments

	Successor
	September 30, 2008		December 31, 2007
Nuclear decommissioning trust	$	434	$	484
Assets related to employee benefit plans, including employee savings programs, net of distributions		220		306
Land		44		44
Note receivable from Capgemini		25		25
Investment in unconsolidated affiliates		1		2
Wind investment project		3		3
Miscellaneous other		4		4
Total investments	$	731	$	868

Property, Plant and Equipment

As of September 30, 2008 and December 31, 2007, property, plant and equipment of $29.6 billion and $28.7 billion, respectively, is stated net of accumulated depreciation and amortization of $5.1 billion and $4.1 billion, respectively. Property, plant and equipment was fair-valued in connection with purchase accounting for the Merger. As a result of cost-based regulatory rate-setting processes, the book value of the majority of Oncor’s assets and liabilities effectively represent fair value, and no adjustments to those regulated assets or liabilities were recorded.

Asset Retirement Obligations

Asset retirement obligations primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to the recognition of the asset retirement costs for nuclear decommissioning, as all costs are recoverable through the regulatory process as part of Oncor’s rates.

The following table summarizes the changes to the asset retirement liability, reported in other noncurrent liabilities and deferred credits in the balance sheet, during the nine months ended September 30, 2008:

	Successor
Asset retirement liability at January 1, 2008	$	773
Additions:
Accretion and incremental reclamation costs		38
Reductions:
Mining reclamation payments		(15	)
Asset retirement liability at September 30, 2008	$	796

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Regulatory Assets and Liabilities

	Successor
	September 30, 2008		December 31, 2007
Regulatory assets
Generation-related regulatory assets securitized by transition bonds	$	893	$	967
Employee retirement costs		267		265
Self-insurance reserve (primarily storm recovery costs)		179		149
Securities reacquisition costs		99		105
Recoverable deferred income taxes—net		79		84
Nuclear decommissioning cost under-recovery		67		—
Employee severance costs		20		20
Other		8		3
Total regulatory assets		1,612		1,593
Regulatory liabilities
Committed spending for demand side management initiatives		98		100
Investment tax credit and protected excess deferred taxes		49		55
Over-collection of securitization (transition) bond revenues		34		34
Credit due REPs under PUCT stipulation		1		72
Nuclear decommissioning cost over-recovery		—		13
Other regulatory liabilities		11		14
Total regulatory liabilities		193		288
Net regulatory assets	$	1,419	$	1,305

Regulatory assets that have been reviewed and approved by the PUCT and are not earning a return totaled $921 million and $997 million at September 30, 2008 and December 31, 2007, respectively, including the generation-related regulatory assets securitized by transition bonds that have a remaining recovery period of approximately eight years. As part of purchase accounting, the carrying value of the generation-related regulatory assets was reduced by $213 million, and this amount is being accreted to other income over the approximate nine-year recovery period remaining as of the date of the Merger.

As of September 30, 2008, regulatory assets totaling $552 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
	September 30, 2008		December 31, 2007
Unfavorable purchase and sales contracts	$	735	$	751
Uncertain tax positions (including accrued interest)		1,668		1,939
Asset retirement obligations		796		773
Retirement plan and other employee benefits		914		1,076
Other		101		111
Total other noncurrent liabilities and deferred credits	$	4,214	$	4,650

Unfavorable Purchase and Sales Contracts—Unfavorable purchase and sales contracts primarily represent the extent to which contracts on a net basis were unfavorable to market prices as of the date of the Merger. These

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are contracts for which: 1) TCEH has made the “normal” purchase or sale election allowed or 2) the contract did not meet the definition of a derivative under SFAS 133. Under purchase accounting, TCEH recorded the value as of October 10, 2007 as a deferred credit. Amortization of the deferred credit related to unfavorable contracts is primarily on a straight-line basis, which approximates the economic realization, and is recorded as revenues or a reduction of purchased power costs as appropriate. The amortization amount totaled $6 million and $23 million in the three and nine months ended September 30, 2008, respectively. 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:

Year	Successor Amount
2008	$	30
2009		28
2010		27
2011		27
2012		27

Uncertain Tax Positions—During the third quarter of 2008, EFH Corp. participated in negotiations with the IRS regarding the 2002 worthlessness loss associated with its discontinued Europe business and has reduced the liability for uncertain tax positions to reflect the most likely settlement of the issue. The reduction in the liability of approximately $375 million was largely offset by a reduction of deferred tax assets related to alternative minimum tax. The conclusion of issues contested from the 1997-2002 audit, including Europe, is not expected to occur prior to December 2009.

EFH Corp. filed a claim in 2006 for refund of income taxes and related interest paid in 2005 associated with IRS audits of 1993 and 1994 tax returns of a discontinued operation. Upon adoption of FIN 48 in 2007, the expected refund was accounted for as a reduction of noncurrent liabilities related to uncertain tax positions. EFH Corp. believes it is reasonably possible this claim could be settled, including approval by the Joint Committee on Taxation, within the next 12 months. The recording of the receipt of the refund, which is expected to total approximately $100 million, is not expected to have a material effect on EFH Corp.’s net income. The carrying amount related to the claim, which is classified as a current income tax receivable as of September 30, 2008, includes $43 million of tax and approximately $50 million of interest.

Supplemental Cash Flow Information

	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Cash payments related to:
Interest paid	$	2,262		$	650
Capitalized interest		(225	)		(75	)
Interest paid (net of capitalized interest)		2,037			575
Income taxes		(61	)		270
Noncash investing and financing activities:
Below market values of power sales agreements (a)		—			264
Noncash construction expenditures (b)		180			206
Promissory note issued in conjunction with acquisition of mining-related assets		—			65
Capital leases		13			52

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(a) Multi-year power sales agreement entered into with Alcoa Inc. and recorded as part of the construction work-in-process asset balance for the Sandow 5 coal-fueled generation unit.

(b) Represents end-of-period accruals.

16. SUBSEQUENT EVENTS

On November 5, 2008, Oncor issued and sold 19.75% of its outstanding equity interests to Texas Transmission Investment LLC (Buyer), an entity indirectly owned by a private investment group led by OMERS Administration Corporation, acting through its infrastructure investment entity Borealis Infrastructure Management Inc., and the Government of Singapore Investment Corporation, acting through its private equity and infrastructure arm GIC Special Investments Pte Ltd. (Issuance).

The consideration paid by the Buyer for the equity interests issued and sold in the Issuance was $1.254 billion. At the closing of the Issuance, Oncor also offered and sold approximately 0.21% of its outstanding equity interests to certain members of Oncor’s management team (Management Equity Offering). Accordingly, after giving effect to the closing of the Issuance and the Management Equity Offering, EFH Corp. indirectly owns approximately 80.04% of Oncor, Oncor management owns approximately 0.21% of Oncor and the Buyer owns 19.75% of Oncor.

The proceeds (net of closing costs) of $1.253 billion received by Oncor from the Buyer and the members of Oncor management upon completion of the Issuance and the Management Equity Offering were distributed ultimately to EFH Corp. Under the terms of certain financing arrangements of EFH Corp. and TCEH, upon such distribution, under certain circumstances, EFH Corp. is required to repay certain outstanding intercompany loans from TCEH. As of November 5, 2008, $837 million of such intercompany loans were outstanding.

17. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

On October 31, 2007, EFH Corp. refinanced the entire $4.5 billion outstanding under its Senior Unsecured Interim Facility obtained to finance the Merger with $2.0 billion 10.875% Senior Notes Due 2017 and $2.5 billion 11.25%/12.00% Senior Toggle Notes Due 2017 (collectively, the EFH Corp. Notes). The EFH Corp. Notes are unconditionally guaranteed by EFC Holdings and Intermediate Holding, 100% owned subsidiaries of EFH Corp. (collectively, the Guarantors) on an unsecured basis. The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the EFH Corp. Notes. The guarantees rank equally with any senior unsecured indebtedness of the Guarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. All other subsidiaries of EFH Corp., either direct or indirect, do not guarantee the EFH Corp. Notes (collectively, the Non-Guarantors). The EFH Corp. Indenture contains certain restrictions, subject to certain exceptions, on EFH Corp.’s ability to pay dividends or make investments.

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The following tables present the condensed consolidating statements of income of EFH Corp. (the Parent/Issuer), the Guarantors and the Non-Guarantors for the three-month and nine-month periods ended September 30, 2008 and 2007, the condensed consolidating statements of cash flows of the Parent/Issuer, the Guarantors and the Non-Guarantors for the nine-month periods ended September 30, 2008 and 2007 and the condensed consolidating balance sheets as of September 30, 2008 and December 31, 2007 of the Parent/Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5-J, Push Down Basis of Accounting Required in Certain Limited Circumstances, including the push down of the $4.5 billion EFH Corp. Notes to the Guarantors.

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Three Months Ended September 30, 2008

(millions of dollars)

	Successor
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	3,695		$	—		$	3,695
Fuel, purchased power costs and delivery fees		—			—			(1,631	)		—			(1,631	)
Net gain from commodity hedging and trading activities		—			—			6,045			—			6,045
Operating costs		—			—			(372	)		2			(370	)
Depreciation and amortization		—			—			(431	)		—			(431	)
Selling, general and administrative expenses		(29	)		—			(219	)		(1	)		(249	)
Franchise and revenue-based taxes		—			—			(92	)		—			(92	)
Other income		—			—			14			—			14
Other deductions		(9	)		—			(532	)		—			(541	)
Interest income		43			—			44			(78	)		9
Interest expense and related charges		(229	)		(131	)		(677	)		206			(831	)
Income (loss) from continuing operations before income taxes		(224	)		(131	)		5,844			129			5,618
Income tax (expense) benefit		87			45			(2,088	)		(45	)		(2,001	)
Equity earnings of subsidiaries		3,754			3,768			—			(7,522	)		—
Net loss	$	3,617		$	3,682		$	3,756		$	(7,438	)	$	3,617

F-51

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Three Months Ended September 30, 2007

(millions of dollars)

	Predecessor
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	2,983		$	—		$	2,983
Fuel, purchased power costs and delivery fees		—			—			(882	)		—			(882	)
Net gain from commodity hedging and trading activities		—			—			462			—			462
Operating costs		—			—			(350	)		—			(350	)
Depreciation and amortization		—			—			(208	)		(1	)		(209	)
Selling, general and administrative expenses		(21	)		—			(208	)		—			(229	)
Franchise and revenue-based taxes		1			—			(94	)		—			(93	)
Other income		—			—			20			—			20
Other deductions		(23	)		—			13			—			(10	)
Interest income		51			76			120			(228	)		19
Interest expense and related charges		(197	)		(70	)		(187	)		228			(226	)
Income (loss) from continuing operations before income taxes		(189	)		6			1,669			(1	)		1,485
Income tax (expense) benefit		73			(1	)		(578	)		—			(506	)
Equity earnings of subsidiaries		1,106			1,119			—			(2,225	)		—
Income from continuing operations		990			1,124			1,091			(2,226	)		979
Income from discontinued operations, net of tax effect		2			—			11			—			13
Net income	$	992		$	1,124		$	1,102		$	(2,226	)	$	992

F-52

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Nine Months Ended September 30, 2008

(millions of dollars)

	Successor
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	9,001		$	—		$	9,001
Fuel, purchased power costs and delivery fees		—			—			(3,867	)		—			(3,867	)
Net loss from commodity hedging and trading activities		—			—			(248	)		—			(248	)
Operating costs		—			—			(1,120	)		—			(1,120	)
Depreciation and amortization		—			—			(1,217	)		—			(1,217	)
Selling, general and administrative expenses		(84	)		—			(628	)		—			(712	)
Franchise and revenue-based taxes		—			1			(260	)		—			(259	)
Other income		—			—			43			—			43
Other deductions		(17	)		—			(566	)		—			(583	)
Interest income		122			5			113			(218	)		22
Interest expense and related charges		(679	)		(401	)		(2,034	)		609			(2,505	)
Loss from continuing operations before income taxes		(658	)		(395	)		(783	)		391			(1,445	)
Income tax benefit		217			134			242			(131	)		462
Equity earnings of subsidiaries		(542	)		(502	)		—			1,044			—
Net loss	$	(983	)	$	(763	)	$	(541	)	$	1,304		$	(983	)

F-53

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Nine Months Ended September 30, 2007

(millions of dollars)

	Predecessor
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	7,743		$	—		$	7,743
Fuel, purchased power costs and delivery fees		—			—			(2,286	)		—			(2,286	)
Net loss from commodity hedging and trading activities		—			—			(607	)		—			(607	)
Operating costs		—			—			(1,065	)		—			(1,065	)
Depreciation and amortization		—			—			(612	)		—			(612	)
Selling, general and administrative expenses		(61	)		—			(615	)		2			(674	)
Franchise and revenue-based taxes		1			(1	)		(270	)		1			(269	)
Other income		—			—			65			—			65
Other deductions		(107	)		—			(794	)		—			(901	)
Interest income		128			202			344			(621	)		53
Interest expense and related charges		(546	)		(184	)		(531	)		617			(644	)
Income (loss) from continuing operations before income taxes		(585	)		17			1,372			(1	)		803
Income tax (expense) benefit		225			(6	)		(430	)		(1	)		(212	)
Equity earnings of subsidiaries		973			1,485			—			(2,458	)		—
Income from continuing operations		613			1,496			942			(2,460	)		591
Income from discontinued operations, net of tax effect		2			—			22			—			24
Net income (loss)	$	615		$	1,496		$	964		$	(2,460	)	$	615

F-54

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Nine Months Ended September 30, 2008

(millions of dollars)

	Successor
	Parent/ Issuer			Guarantor			Non-guarantors			Eliminations			Consolidated
Cash flows—operating activities:
Net loss	$	(983	)	$	(763	)	$	(541	)	$	1,304		$	(983	)
Adjustments to reconcile loss to cash provided by (used in) operations:
Equity in losses of subsidiaries		542			502			—			(1,044	)		—
Depreciation and amortization		42			18			1,511			(17	)		1,554
Deferred income tax benefit—net		74			2			(509	)		—			(433	)
Impairment of emission allowances intangible assets		—			—			501			—			501
Effect of Parent’s payment of interest on pushed down debt		—			252			—			(252	)		—
Unrealized net losses from mark-to-market valuations		—			—			221			—			221
Other, net		18			—			74			—			92
Net change in operating assets and liabilities:
Margin deposits—net		—			—			(236	)		—			(236	)
Other operating assets and liabilities		171			281			206			(417	)		241
Cash provided by (used in) operating activities		(136	)		292			1,227			(426	)		957
Cash flows—financing activities:
Issuances of securities:
Long-term debt		—			—			2,777			—			2,777
Common stock		34			—			—			—			34
Retirements/repurchases of securities:
Long-term debt		(200	)		(2	)		(472	)		—			(674	)
Common stock		(1	)		—			—			—			(1	)
Change in short-term borrowings		—			—			902			—			902
Cash dividends paid		—			(213	)		(213	)		426			—
Change in advances—affiliates		269			—			—			(269	)		—
Other, net		—			—			14			—			14
Cash provided by (used in) financing activities		102			(215	)		3,008			157			3,052
Cash flows—investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(2,179	)		—			(2,179	)
Investments held in money market fund		—			—			(242	)		—			(242	)
Proceeds from sales of environmental allowances and credits		—			—			30			—			30
Purchases of environmental allowances and credits		—			—			(18	)		—			(18	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			747			—			747
Investments in nuclear decommissioning trust fund securities		—			—			(758	)		—			(758	)
Change in advances—affiliates		—			(77	)		(192	)		269			—
Other, net		2			—			44			—			46
Cash provided by (used in) investing activities		2			(77	)		(2,568	)		269			(2,374	)
Net change in cash and cash equivalents		(32	)		—			1,667			—			1,635
Cash and cash equivalents—beginning balance		32			—			249			—			281
Cash and cash equivalents—ending balance	$	—		$	—		$	1,916		$	—		$	1,916

F-55

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Nine Months Ended September 30, 2007

(millions of dollars)

	Predecessor
	Parent/ Issuer			Guarantor			Non-guarantors			Eliminations			Consolidated
Cash flows—operating activities:
Net income	$	615		$	1,496		$	964		$	(2,460	)	$	615
Income from discontinued operations, net of tax		(2	)		—			(22	)		—			(24	)
Income from continuing operations		613			1,496			942			(2,460	)		591
Adjustments to reconcile income to cash provided by operations:
Equity in (earnings) losses of subsidiaries		(973	)		(1,485	)		—			2,458			—
Depreciation and amortization		—			—			660			—			660
Deferred income tax benefit—net		(8	)		2			(224	)		—			(230	)
Impairment and other asset writedown charges		68			—			703			—			771
Unrealized net losses from mark-to-market valuations		—			—			703			—			703
Other, net		19			—			(11	)		—			8
Net change in operating assets and liabilities:
Margin deposits—net		—			—			(769	)		—			(769	)
Other operating assets and liabilities		1,192			1,096			(269	)		(2,198	)		(179	)
Cash provided by operating activities of continuing operations		911			1,109			1,735			(2,200	)		1,555
Cash flows—financing activities:
Issuances of securities:
Long-term debt		—			—			1,800			—			1,800
Common stock		1			—			—			—			1
Retirements/repurchases of securities:
Long-term debt		(1	)		(12	)		(432	)		—			(445	)
Common stock		(13	)		—			—			—			(13	)
Change in short-term borrowings		—			—			684			—			684
Cash dividends paid		(594	)		(1,102	)		(1,102	)		2,204			(594	)
Change in advances—affiliates		(155	)		—			—			155			—
Other, net		(93	)		—			(17	)		—			(110	)
Cash provided by (used in) financing activities		(855	)		(1,114	)		933			2,359			1,323
Cash flows—investing activities:
Capital expenditures and nuclear fuel purchases		(55	)		—			(2,395	)		—			(2,450	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			402			—			402
Investments in nuclear decommissioning trust fund securities		—			—			(413	)		—			(413	)
Change in advances—affiliates		—			5			154			(159	)		—
Other, net		(1	)		—			177			—			176
Cash provided by (used in) investing activities		(56	)		5			(2,075	)		(159	)		(2,285	)
Cash flows—discontinued operations:
Operating activities		—			—			28			—			28
Financing activities		—			—			—			—			—
Investing activities		—			—			—			—			—
Cash provided by discontinued operations		—			—			28			—			28
Net change in cash and cash equivalents		—			—			621			—			621
Cash and cash equivalents—beginning balance		—			—			25			—			25
Cash and cash equivalents—ending balance	$	—		$	—		$	646		$	—		$	646

F-56

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at September 30, 2008

(millions of dollars)

	Successor
	Parent/ Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—	$	1,916	$	—		$	1,916
Investments held in money market fund		—		—		242		—			242
Restricted cash		—		—		84		—			84
Advances to parent		278		85		—		(363	)		—
Trade accounts receivable—net		5		—		1,229		—			1,234
Income taxes receivable		—		176		259		(214	)		221
Accounts receivable from affiliates		5		—		—		(5	)		—
Notes receivable from affiliates		—		—		448		(448	)		—
Inventories		—		—		412		—			412
Commodity and other derivative contractual assets		17		—		1,538		—			1,555
Accumulated deferred income taxes		—		1		43		(44	)		—
Margin deposits related to commodity positions		—		—		766		—			766
Other current assets		5		—		135		—			140
Total current assets		310		262		7,072		(1,074	)		6,570
Restricted cash		—		—		1,267		—			1,267
Investments		14,258		13,045		665		(27,237	)		731
Property, plant and equipment—net		—		—		29,600		—			29,600
Notes receivable from affiliates		12		—		2,282		(2,294	)		—
Goodwill		—		—		22,930		—			22,930
Intangible assets—net		—		—		3,565		—			3,565
Regulatory assets—net		—		—		1,419		—			1,419
Commodity and other derivative contractual assets		—		—		340		—			340
Accumulated deferred income taxes		383		7		—		(390	)		—
Unamortized debt issuance costs and other noncurrent assets		135		115		935		(116	)		1,069
Total assets	$	15,098	$	13,429	$	70,075	$	(31,111	)	$	67,491
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	—	$	—	$	2,620	$	—		$	2,620
Advances from affiliates		—		—		363		(363	)		—
Long-term debt due currently		—		7		409		—			416
Trade accounts payable		6		—		1,217		—			1,223
Accounts payable to affiliates		—		—		5		(5	)		—
Notes payable to affiliates		407		6		35		(448	)		—
Commodity and other derivative contractual liabilities		50		—		1,956		—			2,006
Margin deposits related to commodity positions		—		—		22		—			22
Accumulated deferred income taxes		50		—		—		(44	)		6
Accrued interest		272		210		601		(208	)		875
Other current liabilities		106		—		513		(37	)		582
Total current liabilities		891		223		7,741		(1,105	)		7,750
Accumulated deferred income taxes		—		—		6,918		(390	)		6,528
Investment tax credits		—		—		43		—			43
Commodity and other derivative contractual liabilities		—		—		2,456		—			2,456
Notes or other liabilities due affiliates		2,019		—		275		(2,294	)		—
Long-term debt, less amounts due currently		6,329		4,602		34,436		(4,500	)		40,867
Other noncurrent liabilities and deferred credits		226		—		3,988		—			4,214
Total liabilities		9,465		4,825		55,857		(8,289	)		61,858
Shareholders’ equity		5,633		8,604		14,218		(22,822	)		5,633
Total liabilities and shareholders’ equity	$	15,098	$	13,429	$	70,075	$	(31,111	)	$	67,491

F-57

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Consolidating Balance Sheets

at December 31, 2007

(millions of dollars)

	Successor
	Parent/ Issuer		Guarantors		Non-guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	32	$	—	$	249	$	—		$	281
Restricted cash		—		—		56		—			56
Advances to parent		378		1		—		(379	)		—
Trade accounts receivable—net		28		—		1,071		—			1,099
Income taxes receivable		—		44		366		(309	)		101
Accounts receivable from affiliates		—		82		29		(111	)		—
Notes receivable from affiliates		—		—		59		(59	)		—
Inventories		—		—		405		—			405
Commodity and other derivative contractual assets		3		—		1,126		—			1,129
Accumulated deferred income taxes		—		1		76		(68	)		9
Margin deposits related to commodity positions		—		—		513		—			513
Other current assets		253		—		123		—			376
Total current assets		694		128		4,073		(926	)		3,969
Restricted cash		—		—		1,296		—			1,296
Investments		15,157		13,860		749		(28,898	)		868
Property, plant and equipment—net		—		—		28,650		—			28,650
Notes receivable from affiliates		12		—		2,308		(2,320	)		—
Goodwill		—		—		22,954		—			22,954
Intangible assets—net		—		—		4,365		—			4,365
Regulatory assets—net		—		—		1,305		—			1,305
Commodity and other derivative contractual assets		—		—		244		—			244
Accumulated deferred income taxes		478		19		—		(497	)		—
Unamortized debt issuance costs and other noncurrent assets		144		132		986		(132	)		1,130
Assets held for sale		—		—		23		—			23
Total assets	$	16,485	$	14,139	$	66,953	$	(32,773	)	$	64,804
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings	$	—	$	—	$	1,718	$	—		$	1,718
Advances from affiliates		—		—		379		(379	)		—
Long-term debt due currently		200		7		306		—			513
Trade accounts payable		6		—		898		—			904
Accounts payable to affiliates		110		—		—		(110	)		—
Notes payable to affiliates		25		—		34		(59	)		—
Commodity and other derivative contractual liabilities		38		—		1,108		—			1,146
Margin deposits related to commodity positions		—		—		5		—			5
Accumulated deferred income taxes		69		—		—		(69	)		—
Accrued interest		114		87		422		(86	)		537
Other current liabilities		556		—		586		(263	)		879
Total current liabilities		1,118		94		5,456		(966	)		5,702
Accumulated deferred income taxes		—		—		7,161		(497	)		6,664
Investment tax credits		—		—		47		—			47
Commodity and other derivative contractual liabilities		—		—		2,453		—			2,453
Notes or other liabilities due affiliates		2,019		—		301		(2,320	)		—
Long-term debt, less amounts due currently		6,288		4,603		32,212		(4,500	)		38,603
Other noncurrent liabilities and deferred credits		375		—		4,275		—			4,650
Total liabilities		9,800		4,697		51,905		(8,283	)		58,119
Shareholders’ equity		6,685		9,442		15,048		(24,490	)		6,685
Total liabilities and shareholders’ equity	$	16,485	$	14,139	$	66,953	$	(32,773	)	$	64,804

F-58

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 (“EFH Corp.”) 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). These financial statements are the responsibility of EFH Corp.’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

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

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

As discussed in Note 1 to the consolidated financial statements, EFH Corp. completed its merger with Texas Energy Future Merger Sub Corp and became a subsidiary of Texas Energy Future Holdings Limited Partnership on October 10, 2007. Also as discussed in Note 1, EFH Corp. adopted the provisions of FASB Staff Position No. FIN 39-1 and reclassified the results of its commodity hedging and trading activities on a retrospective basis.

/s/ Deloitte & Touche LLP

Dallas, Texas

March 31, 2008

(September 17, 2008 as to (1) the effects of the adoption of FASB Staff Position No. FIN 39-1 and the effects of the reclassification of results of EFH Corp.’s commodity hedging and trading activities as described in Note 1, and (2) Note 29)

F-59

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	$	1,994		$	8,044		$	10,703		$	10,826
Fuel, purchased power costs and delivery fees		(644	)		(2,381	)		(2,784	)		(4,261	)
Net gain (loss) from commodity hedging and trading activities		(1,492	)		(554	)		153			(164	)
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	)
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.

F-60

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
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		1			24			87			5
Extraordinary loss, net of tax effect		—			—			—			(50	)
Cumulative effect of changes in accounting principles, net of tax effect		—			—			—			(8	)
Net income (loss)	$	(1,360	)	$	723		$	2,552		$	1,722
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, $154, $(321) and $53)		(177	)		(288	)		598			(100	)
Derivative value net (gains) losses related to hedged transactions recognized during the period and reported in net income (net of tax (expense) benefit of $—, $(48), $(25) and $71)		—			(89	)		(45	)		130
Total effect of cash flow hedges		(177	)		(377	)		553			30
Total adjustments to net income		(234	)		(328	)		624			(16	)
Comprehensive income (loss)	$	(1,594	)	$	395		$	3,176		$	1,706

See Notes to Financial Statements.

F-61

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.

F-62

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.

F-63

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)		1,129		2,194
Accumulated deferred income taxes (Note 14)		9		253
Margin deposits related to commodity positions		513		7
Other current assets		376		177
Total current assets		3,969		4,056
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)		244		484
Unamortized debt issuance costs and other noncurrent assets		1,130		380
Assets held for sale		23		—
Total assets	$	64,804	$	27,216
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)		1,146		1,537
Margin deposits related to commodity positions		5		681
Accrued interest		537		159
Other current liabilities		879		881
Total current liabilities		5,702		6,327
Accumulated deferred income taxes (Note 14)		6,664		4,238
Investment tax credits		47		363
Commodity and other derivative contractual liabilities (Note 20)		2,453		330
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		58,119		25,076
Commitments and Contingencies (Note 18)
Shareholders’ equity (Note 19)		6,685		2,140
Total liabilities and shareholders’ equity	$	64,804	$	27,216

See Notes to Financial Statements.

F-64

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.

F-65

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; 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 Luminant, 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 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.

EFH Corp. has two reportable segments: the Competitive Electric segment, which includes the activities of TCEH as well as equipment salvage and resale activities related to the canceled development of new generation facilities, and the Regulated Delivery segment, which includes the activities of Oncor, its wholly-owned

F-66

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, a change to discontinue the netting of derivative assets and liabilities under master netting agreements as allowed under FIN 39-1, a change in classification to report the results of commodity hedging and trading activities on a separate line item in the income statement instead of within operating revenues, as discussed below, certain reclassifications in the statements of consolidated comprehensive income (loss) to conform to current presentation and changes in accounting policies also 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.

Change in Classification of Results from Commodity Hedging and Trading Activities—Effective April 1, 2008, EFH Corp. changed its classification of realized and unrealized net gains and losses from commodity hedging and trading activities such that the results from these activities are reported as a separate line on the income statement. Prior to April 2008, such amounts were included within operating revenues. EFH Corp. believes this change in classification provides users of the financial statements better transparency of underlying revenue trends. Results from commodity hedging and trading activities are volatile as a substantial majority of the activity involves natural gas financial instruments, which are used to economically hedge future cash flows from electricity sales and are marked-to-market in net income. Comparative financial statements of prior periods reflect this reclassification. The following table presents EFH Corp.’s operating revenues as previously reported and reflects the change in classification. There is no effect on reported earnings, the balance sheet or the statement of cash flows as a result of this change in presentation.

	Successor						Predecessor
	As Originally Reported			As Reclassified			As Originally Reported		As Reclassified			As Originally Reported		As Reclassified
	Period from October 11, 2007 through December 31, 2007			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007		Period from January 1, 2007 through October 10, 2007			Year Ended December 31, 2006		Year Ended December 31, 2006
Operating revenues	$	502		$	1,994		$	7,490	$	8,044		$	10,856	$	10,703
Net gain (loss) from commodity hedging and trading activities		n/a			(1,492	)		n/a		(554	)		n/a		153
Income (loss) from continuing operations		(1,361	)		(1,361	)		699		699			2,465		2,465

F-67

	Predecessor
	As Originally Reported		As Reclassified
	Year Ended December 31, 2005		Year Ended December 31, 2005
Operating revenues	$	10,662	$	10,826
Net gain (loss) from commodity hedging and trading activities		n/a		(164	)
Income (loss) from continuing operations		1,775		1,775

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.

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

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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.

Realized and unrealized gains and losses from transacting in energy-related derivative instruments are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

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).

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 in the income statement in net gain (loss) from commodity hedging and trading activities. 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

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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.

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.

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.

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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.

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.

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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.

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

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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.

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.

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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.

Effective January 1, 2008, EFH Corp. adopted FIN 39-1, “Amendment of FASB Interpretation No. 39”. This FSP provides additional guidance regarding the offsetting in the balance sheet of cash collateral and derivative fair value asset and liability amounts. As provided for by this new rule, for balance sheet presentation, EFH Corp. elected to not adopt netting of cash collateral, and further to discontinue netting of derivative assets and liabilities under master netting agreements. Accordingly, as required by the rule, prior period amounts in the financial statements reflect the change in presentation, resulting in an increase of $849 million and $171 million in both commodity and other derivative contractual current and noncurrent assets and liabilities, respectively, at December 31, 2007 and an increase of $1.244 billion and $139 million in both commodity and other derivative contractual current and noncurrent assets and liabilities, respectively, at December 31, 2006 compared to previously reported amounts.

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 (Note 17)		4.5	Repayment of existing debt (Note 17)		5.3
			Restricted cash		1.2
Equity contributions (a)		8.3	Financing fees related to new facilities		0.9
Total source of funds	$	40.1	Total uses of funds	$	40.1

(a) Consists of equity contributions by the Sponsor Group and certain other investors.

(b) Represents 461.2 million outstanding shares of EFH Corp. common stock multiplied by $69.25 per share.

(c) Represents professional fees incurred by the Sponsor Group that were directly associated with the Merger and accounted for as part of the purchase price.

Purchase Price Allocation

EFH Corp. accounted for the Merger under purchase accounting in accordance with the provisions of SFAS 141, whereby the total purchase price of the transaction was allocated to EFH Corp.’s identifiable tangible and

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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 as of December 31, 2007 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.

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

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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	$	10,045		$	10,712
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. None of this goodwill balance is being deducted for tax purposes.

As discussed in Note 2, EFH Corp. accounted for the Merger under purchase accounting. The 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.

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		Amortization		Net		Gross Carrying Amount		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

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Amortization expense related to intangible assets consisted of:

	Successor			Predecessor
	Useful lives at December 31, 2007 (weighted average in years)	Period from October 11, 2007 through December 31, 2007		Period From January 1, 2007 through October 10, 2007		Year Ended December 31,
						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 (reported in the Competitive Electric segment).

• 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 (reported in the Competitive Electric segment). Unfavorable purchase and sales contracts are recorded as other noncurrent liabilities and deferred credits (see Note 28).

• Trade name—The trade name intangible asset represents the 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”.

• 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 (reported in the Competitive Electric segment).

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

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4. DISCONTINUED OPERATIONS

Results from discontinued operations during the period October 11, 2007 to December 31, 2007 totaled $1 million in net income and during the period from January 1, 2007 to October 10, 2007 totaled $24 million in net income and consisted primarily of insurance proceeds related to the 2005 TXU Europe litigation settlement agreement in both periods.

Results from discontinued operations in 2006 totaled $87 million in net income. This amount included a $62 million credit representing reversal of a TXU Gas income tax reserve, due to favorable resolution of an IRS audit matter relating to a business sold in 2000, and a total of $27 million ($42 million pretax) in credits representing insurance recoveries associated with the TXU Europe settlement agreement. (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.

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.

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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	)

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

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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.

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.

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• 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).

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

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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.

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

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$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
Unfavorable purchase and sales contracts		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, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31,
							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

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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 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

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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-.

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 December 31, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31,
							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.

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Activities of TXU Receivables Company were 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
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	)

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.

F-89

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.

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.

F-90

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.

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

F-92

	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-93

(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.

(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.

F-94

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.

F-95

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.

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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.

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

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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.

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.

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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.

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

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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 ratings, its LIBOR-based borrowings as of December 31, 2007 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 ratings, its facility fee at December 31, 2007 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.

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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.

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.

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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.

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.

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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.

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.

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

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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.

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.

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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.

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

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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.

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

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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.

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.

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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.

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

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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.

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

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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.

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

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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. Accordingly, essentially all of EFH Corp.’s net income is restricted from being used to make distributions on its common stock unless such distributions are expressly permitted under the indenture and/or after such distributions, on a pro forma basis, after giving effect to such payment, the consolidated leverage ratio of EFH Corp. is equal to or less than 7.0 to 1.0. Consolidated leverage ratio is generally defined as the ratio of consolidated total indebtedness (as defined in the indenture) of EFH Corp. to Adjusted EBITDA of EFH Corp., in each case, on a consolidated basis, excluding Oncor Holdings and its subsidiaries. In addition, the TCEH Senior Secured Facilities generally restrict TCEH from making any distribution to any of its parent companies for the ultimate purpose of making a distribution to Texas Holdings unless at the time, and after giving effect to such distribution, TCEH’s consolidated total debt (as defined in the TCEH Senior Secured Facilities) to TCEH’s Adjusted EBITDA would be equal to or less than 6.5 to 1.0.

Common Stock Registration Rights—The Sponsor Group and certain other investors entered into a registration rights agreement with EFH Corp. upon closing of the Merger. Pursuant to this agreement, in certain instances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.’s common stock owned directly or indirectly by them under the Securities Act. In certain instances, the Sponsor Group and certain other investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.’s common stock under the Securities Act that it may undertake.

See Note 23 for discussion of stock-based compensation plans.

Predecessor

Declaration of Dividend—At its August 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 per share, which was paid October 1, 2007 to shareholders of record on September 7, 2007. At its May 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 per share, which was paid on July 2, 2007 to shareholders of record on June 1, 2007. At its February 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 a share, payable April 2, 2007 to shareholders of record on March 2, 2007.

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.

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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).

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	$	1,118		$	11		$	—		$	1,129
Noncurrent assets		239			5			—			244
Total	$	1,357		$	16		$	—		$	1,373
Liabilities:
Current liabilities	$	1,042		$	104		$	—		$	1,146
Noncurrent liabilities		2,232			221			—			2,453
Total	$	3,274		$	325		$	—		$	3,599
Net assets (liabilities)	$	(1,917	)	$	(309	)	$	—		$	(2,226	)
	Predecessor
	December 31, 2006
	Commodity contracts			Cash flow hedges and other derivatives			Netting adjustments (a)			Total
Assets:
Current assets	$	1,438		$	773		$	(17	)	$	2,194
Noncurrent assets		310			254			(80	)		484
Total	$	1,748		$	1,027		$	(97	)	$	2,678
Liabilities:
Current liabilities	$	1,441		$	113		$	(17	)	$	1,537
Noncurrent liabilities		330			80			(80	)		330
Total	$	1,771		$	193		$	(97	)	$	1,867
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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Margin deposit net assets of $445 million and margin deposit net liabilities of $648 million under master netting arrangements at December 31, 2007 and 2006, respectively, were not netted with derivative assets and liabilities since EFH Corp. has elected to present the amounts of such assets and liabilities gross in the balance sheet as provided in FIN 39-1 and discussed in Note 1.

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	$	1,014
Interest rate swaps		8		4
Other		—		9
Total	$	16	$	1,027
Current and noncurrent liabilities:
Commodity-related cash flow hedges	$	1	$	104
Interest rate swaps		324		89
Total	$	325	$	193

Other Cash Flow Hedge Information—EFH Corp. experienced cash flow hedge ineffectiveness of $111 million in net gains in 2007 (essentially all of which was in the Predecessor period), $231 million in net gains in 2006 and $31 million in net losses in 2005. These amounts are pretax and are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

The net effect of recording unrealized mark-to-market gains and losses arising from hedge ineffectiveness (versus recording gains and losses upon settlement) includes the above amounts as well as the effect of reversing unrealized ineffectiveness gains and losses recorded in previous periods to offset realized gains and losses in the current period. Such net unrealized effect totaled $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.

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.

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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.

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.

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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.

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, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended 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

Consistent with SFAS 87, EFH Corp. uses the calculated value method to determine the market-related value of the assets held in its trust. EFH Corp. includes the realized and unrealized gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.

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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, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31,
							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
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	)
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
Asset Type	Allocation of Plan Assets 2007		Allocation of Plan Assets 2006		Target Allocation Ranges	Expected Long-Term Returns
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	%

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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, 2007			Period From January 1, 2007 through October 10, 2007			Year Ended December 31,
							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
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate		6.55	%		6.45	%		5.90	%		5.75	%

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	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
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

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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	)

Asset Allocations—

The weighted average asset allocations of the OPEB plan by asset category are as follows:

	Allocation of Plan Assets
	Successor		Predecessor
Asset Type	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.

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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.

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)

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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.

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

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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.

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.

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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.

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.

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• Discount for liquidation restrictions—this factor estimated the discount for lack of marketability of vested awards due to the anticipated time for the approval and issuance of the awards, the black-out period immediately after the grant and additional holding requirements imposed on senior executives. This discount was determined based on an estimation of the cost of a protective put at the award date and is calculated using the Black-Scholes option pricing model using expected volatility assumptions based on historical and implied volatility as discussed above and a risk-free rate of return over the option period.

• For the 2007 grant, change-in-control and no-change-in-control scenarios were considered. The change-in-control scenario was based on three different change-in-control dates each assigned projected probabilities. The change-in-control value was probability weighted with the value assuming no change of control.

Assumptions	Period from January 1, 2007 Through October 10, 2007	2006	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.

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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

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

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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.

• 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

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certain commodities. EFH Corp. believes that development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.

With respect to amounts presented in the following fair value hierarchy table, the fair value measurement of an asset or liability (e.g. a contract) is required under SFAS 157 to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.

At December 31, 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	$	511	$	683	$	148	$	23	$	1,365
Interest rate swaps		—		8		—		—		8
Nuclear decommissioning trust (b)		165		319		—		—		484
Salary deferral plan investments (b)		31		70		—		—		101
Total assets	$	707	$	1,080	$	148	$	23	$	1,958
Liabilities:
Commodity-related contracts	$	559	$	2,372	$	321	$	23	$	3,275
Interest rate swaps		—		324		—		—		324
Total liabilities	$	559	$	2,696	$	321	$	23	$	3,599

(a) Represents the effects of netting assets and liabilities at the counterparty agreement level where the legal right of offset exists.

(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) Substantially all changes in values of commodity-related contracts are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

(b) Settlements represent 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.

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.

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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.

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.

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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.

	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	$	1,671		$	6,884		$	9,396		$	9,716
Regulated Delivery		532			1,987			2,449			2,394
Corp. and Other		11			37			49			30
Eliminations		(220	)		(864	)		(1,191	)		(1,314	)
Consolidated		1,994			8,044			10,703			10,826
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

F-137

	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 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
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	49,297				20,289		20,324
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	64,804				27,216		27,978
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.

F-138

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		1,682			6,921			9,445			9,746
Intercompany sales eliminations—regulated		(208	)		(824	)		(1,139	)		(1,278	)
Intercompany sales eliminations—unregulated		(12	)		(40	)		(52	)		(36	)
Total operating revenues		1,994			8,044			10,703			10,826
Fuel, purchased power and delivery fees—unregulated (a)		(644	)		(2,381	)		(2,784	)		(4,261	)
Net gain (loss) from commodity hedging and trading activities—unregulated		(1,492	)		(554	)		153			(164	)
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	)
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.

F-139

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.

F-140

Property, Plant and Equipment

	Successor		Predecessor
	December 31, 2007		December 31, 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.

F-141

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

F-142

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:

Year	Successor Amount
2008	$	26
2009		25
2010		24
2011		24
2012		24

F-143

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 20)		—		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.

29. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

On October 31, 2007, EFH Corp. refinanced the entire $4.5 billion outstanding under its Senior Unsecured Interim Facility obtained to finance the Merger with $2.0 billion 10.875% Senior Notes Due 2017 and $2.5 billion 11.25%/12.00% Senior Toggle Notes Due 2017 (collectively, the EFH Corp. Notes). The EFH Corp. Notes are unconditionally guaranteed by EFC Holdings and Intermediate Holding, 100% owned subsidiaries of EFH Corp. (collectively, the Guarantors) on a senior unsecured basis. The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the EFH Corp. Notes. The guarantees rank equally with any senior unsecured indebtedness of the Guarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. All other subsidiaries of EFH Corp., either direct or indirect, do not guarantee the EFH Corp. Notes (collectively, the Non-Guarantors). The EFH Corp. Indenture contains certain restrictions, subject to certain exceptions, on EFH Corp.’s ability to pay dividends or make investments.

The following tables present the consolidating statements of income of EFH Corp. (the Parent/Issuer), the Guarantors and the Non-Guarantors for the three years ended December 31, 2007, the consolidating statements of cash flows of the Parent/Issuer, the Guarantors and the Non-Guarantors for the three years ended December 31, 2007 and the consolidating balance sheets as of December 31, 2007 and December 31, 2006 of the Parent/Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5J, Push Down Basis of Accounting Required in Certain Limited Circumstances, including the push down of the $4.5 billion EFH Corp. Notes to the Guarantors.

F-144

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Period From October 11, 2007 through December 31, 2007

(millions of dollars)

	Successor
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	1,994		$	—		$	1,994
Fuel, purchased power costs and delivery fees		—			—			(644	)		—			(644	)
Net loss from commodity hedging and trading activities		—			—			(1,492	)		—			(1,492	)
Operating costs		—			—			(306	)		—			(306	)
Depreciation and amortization		—			—			(416	)		1			(415	)
Selling, general and administrative expenses		(17	)		—			(198	)		(1	)		(216	)
Franchise and revenue-based taxes		(1	)		—			(92	)		—			(93	)
Other income		—			—			14			—			14
Other deductions		(54	)		—			(7	)		—			(61	)
Interest income		54			6			32			(68	)		24
Interest expense and related charges		(234	)		(140	)		(670	)		205			(839	)
Loss from continuing operations before income taxes and equity earnings of subsidiaries		(252	)		(134	)		(1,785	)		137			(2,034	)
Income tax benefit		53			28			637			(45	)		673
Equity earnings of subsidiaries		(1,161	)		(1,142	)		—			2,303			—
Loss from continuing operations		(1,360	)		(1,248	)		(1,148	)		2,395			(1,361	)
Income from discontinued operations, net of tax effect		—			—			1			—			1
Net loss	$	(1,360	)	$	(1,248	)	$	(1,147	)	$	2,395		$	(1,360	)

F-145

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Period From January 1, 2007 through October 10, 2007

(millions of dollars)

	Predecessor
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	8,044		$	—		$	8,044
Fuel, purchased power costs and delivery fees		—			—			(2,381	)		—			(2,381	)
Net loss from commodity hedging and trading activities		—			—			(554	)		—			(554	)
Operating costs		—			—			(1,107	)		—			(1,107	)
Depreciation and amortization		—			—			(634	)		—			(634	)
Selling, general and administrative expenses		(58	)		—			(633	)		—			(691	)
Franchise and revenue-based taxes		—			(1	)		(282	)		1			(282	)
Other income		8			1			60			—			69
Other deductions		(108	)		—			(733	)		—			(841	)
Interest income		133			210			368			(655	)		56
Interest expense and related charges		(566	)		(192	)		(567	)		654			(671	)
Income (loss) from continuing operations before income taxes and equity of earnings of subsidiaries		(591	)		18			1,581			—			1,008
Income tax (expense) benefit		235			(2	)		(542	)		—			(309	)
Equity earnings of subsidiaries		1,077			1,554			—			(2,631	)		—
Income from continuing operations		721			1,570			1,039			(2,631	)		699
Income from discontinued operations, net of tax effect		2			—			22			—			24
Net income	$	723		$	1,570		$	1,061		$	(2,631	)	$	723

F-146

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Year Ended December 31, 2006

(millions of dollars)

	Predecessor
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	10,703		$	—		$	10,703
Fuel, purchased power costs and delivery fees		—			—			(2,784	)		—			(2,784	)
Net gain from commodity hedging and trading activities		—			—			153			—			153
Operating costs		—			—			(1,373	)		—			(1,373	)
Depreciation and amortization		—			—			(830	)		—			(830	)
Selling, general and administrative expenses		(70	)		—			(748	)		(1	)		(819	)
Franchise and revenue-based taxes		(1	)		—			(390	)		1			(390	)
Other income		15			—			106			—			121
Other deductions		(7	)		—			(262	)		—			(269	)
Interest income		74			206			367			(601	)		46
Interest expense and related charges		(609	)		(136	)		(703	)		618			(830	)
Income (loss) from continuing operations before income taxes and equity earnings of subsidiaries		(598	)		70			4,239			17			3,728
Income tax (expense) benefit		214			(17	)		(1,460	)		—			(1,263	)
Equity earnings of subsidiaries		2,936			2,792			—			(5,728	)		—
Income from continuing operations		2,552			2,845			2,779			(5,711	)		2,465
Income from discontinued operations, net of tax effect		—			—			87			—			87
Net income	$	2,552		$	2,845		$	2,866		$	(5,711	)	$	2,552

F-147

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

Year Ended December 31, 2005

(millions of dollars)

	Predecessor
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	10,826		$	—		$	10,826
Fuel, purchased power costs and delivery fees		—			—			(4,261	)		—			(4,261	)
Net loss from commodity hedging and trading activities		—			—			(164	)		—			(164	)
Operating costs		—			—			(1,425	)		—			(1,425	)
Depreciation and amortization		—			—			(776	)		—			(776	)
Selling, general and administrative expenses		(71	)		(1	)		(710	)		1			(781	)
Franchise and revenue-based taxes		—			(1	)		(364	)		1			(364	)
Other income		1			—			151			(1	)		151
Other deductions		26			—			(71	)		—			(45	)
Interest income		117			79			220			(368	)		48
Interest expense and related charges		(412	)		(84	)		(694	)		388			(802	)
Income (loss) from continuing operations before income taxes, equity earnings of subsidiaries, extraordinary loss and cumulative change in accounting principles		(339	)		(7	)		2,732			21			2,407
Income tax (expense) benefit		120			2			(754	)		—			(632	)
Equity earnings of subsidiaries		1,931			1,752			—			(3,683	)		—
Income from continuing operations before extraordinary loss and cumulative change in accounting principles		1,712			1,747			1,978			(3,662	)		1,775
Income (loss) from discontinued operations, net of tax effect		10			—			(5	)		—			5
Extraordinary loss, net of tax effect		—			—			(50	)		—			(50	)
Cumulative effect of changes in accounting principles, net of tax effect		—			—			(8	)		—			(8	)
Net income before preference stock dividends		1,722			1,747			1,915			(3,662	)		1,722
Preference stock dividends		(10	)		—			—			—			(10	)
Net income available for common stock	$	1,712		$	1,747		$	1,915		$	(3,662	)	$	1,712

F-148

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Period From October 11, 2007 through December 31, 2007

(millions of dollars)

	Successor
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows—operating activities:
Net loss	$	(1,360	)	$	(1,248	)	$	(1,147	)	$	2,395		$	(1,360	)
Income from discontinued operations, net of tax		—			—			(1	)		—			(1	)
Loss from continuing operations		(1,360	)		(1,248	)		(1,148	)		2,395			(1,361	)
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Equity in earnings of subsidiaries		1,161			1,142			—			(2,303	)		—
Depreciation and amortization		12			4			556			(4	)		568
Deferred income tax expense (benefit)—net		(357	)		11			(390	)		—			(736	)
Impairments and other asset writedown charges		1			—			1			—			2
Net gains from unrealized mark-to-market valuations		—			—			1,556			—			1,556
Other, net		1			—			15			—			16
Changes in operating assets and liabilities:
Margin deposits—net		—			—			(614	)		—			(614	)
Other		712			(220	)		(285	)		(88	)		119
Cash provided by (used in) operating activities of continuing operations		170			(311	)		(309	)		—			(450	)
Cash flows—financing activities:
Issuance of securities:
Equity financing from Sponsor Group		8,236			—			—			—			8,236
Long-term debt		9,000			—			33,732			—			42,732
Retirements/repurchases of long-term debt		(5,522	)		(4	)		(9,869	)		—			(15,395	)
Change in short term borrowings		—			—			(722	)		—			(722	)
Change in advances—affiliates		33			—			—			(33	)		—
Contributions to parent		—			(21,000	)		(21,000	)		42,000			—
Other, net		(400	)		1			(587	)		—			(986	)
Cash provided by (used in) financing activities		11,347			(21,003	)		1,554			41,967			33,865
Cash flows—investing activities:
Acquisition of EFH Corp.		(32,694	)		—			—			—			(32,694	)
Contribution from subsidiaries		21,000			21,000			—			(42,000	)		—
Capital expenditures and nuclear fuel		(2	)		—			(705	)		—			(707	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			831			—			831
Investments in nuclear decommissioning trust fund securities		—			—			(835	)		—			(835	)
Proceeds from letter of credit facility deposited with trustee		—			—			(1,250	)		—			(1,250	)
Change in advances—affiliates		—			314			(347	)		33			—
Other, net		(3	)		—			95			—			92
Cash provided by (used in) investing activities		(11,699	)		21,314			(2,211	)		(41,967	)		(34,563	)
Cash flows—discontinued operations:
Operating activities		—			—			(7	)		—			(7	)
Financing activities		—			—			—			—			—
Investing activities		—			—			—			—			—
Cash used in discontinued operations		—			—			(7	)		—			(7	)
Net change in cash and equivalents		(182	)		—			(973	)		—			(1,155	)
Cash and cash equivalents—beginning balance		214			—			1,222			—			1,436
Cash and cash equivalents—ending balance	$	32		$	—		$	249		$	—		$	281

F-149

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Period From January 1, 2007 through October 10, 2007

(millions of dollars)

	Predecessor
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows—operating activities:
Net income	$	723		$	1,570		$	1,061		$	(2,631	)	$	723
Income from discontinued operations, net of tax		(2	)		—			(22	)		—			(24	)
Income from continuing operations		721			1,570			1,039			(2,631	)		699
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Equity in earnings of subsidiaries		(1,077	)		(1,554	)		—			2,631			—
Depreciation and amortization		—			—			684			—			684
Deferred income tax expense (benefit)—net		(67	)		1			(45	)		—			(111	)
Impairments and other asset writedown charges		68			—			646			—			714
Net gains from unrealized mark-to-market valuations		—			—			722			—			722
Other, net		20			(1	)		(5	)		—			14
Changes in operating assets and liabilities:
Margin deposits—net		—			—			(569	)		—			(569	)
Other		1,464			1,452			118			(2,922	)		112
Cash provided by operating activities of continuing operations		1,129			1,468			2,590			(2,922	)		2,265
Cash flows—financing activities:
Issuance of securities:
Long-term debt		—			—			1,800			—			1,800
Common stock		1			—			—			—			1
Retirements/repurchases of securities:
Long-term debt		(1	)		(13	)		(431	)		—			(445	)
Common stock		(13	)		—			—			—			(13	)
Change in short term borrowings		—			—			949			—			949
Cash dividends paid		(788	)		(1,461	)		(1,461	)		2,922			(788	)
Change in advances—affiliates		50			—			—			(50	)		—
Other, net		(93	)		—			(17	)		—			(110	)
Cash provided by (used in) financing activities		(844	)		(1,474	)		840			2,872			1,394
Cash flows—investing activities:
Capital expenditures and nuclear fuel		(70	)		—			(2,447	)		—			(2,517	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			602			—			602
Investments in nuclear decommissioning trust fund securities		—			—			(614	)		—			(614	)
Change in advances—affiliates		—			6			(56	)		50			—
Other, net		(1	)		—			247			—			246
Cash provided by (used in) investing activities		(71	)		6			(2,268	)		50			(2,283	)
Cash flows—discontinued operations:
Operating activities		—			—			35			—			35
Financing activities		—			—			—			—			—
Investing activities		—			—			—			—			—
Cash provided by discontinued operations		—			—			35			—			35
Net change in cash and equivalents		214			—			1,197			—			1,411
Cash and cash equivalents—beginning balance		—			—			25			—			25
Cash and cash equivalents—ending balance	$	214		$	—		$	1,222		$	—		$	1,436

F-150

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2006

(millions of dollars)

	Predecessor
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows—operating activities:
Net income	$	2,552		$	2,845		$	2,866		$	(5,711	)	$	2,552
Income from discontinued operations, net of tax		—			—			(87	)		—			(87	)
Income from continuing operations		2,552			2,845			2,779			(5,711	)		2,465
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Equity in earnings of subsidiaries		(2,936	)		(2,792	)		—			5,728			—
Depreciation and amortization		—			—			893			—			893
Deferred income tax expense (benefit)—net		116			(9	)		649			—			756
Impairments and other asset writedown charges		—			—			204			—			204
Net effect of unrealized mark-to-market valuations		—			—			(272	)		—			(272	)
Other, net		6			—			162			—			168
Changes in operating assets and liabilities:
Margin deposits—net		—			—			564			—			564
Other		482			1,528			892			(2,726	)		176
Cash provided by operating activities of continuing operations		220			1,572			5,871			(2,709	)		4,954
Cash flows—financing activities:
Issuance of securities:
Long-term debt		—			—			243			—			243
Common stock		180			—			—			—			180
Retirements/repurchases of securities:
Long-term debt		(911	)		(6	)		(774	)		—			(1,691	)
Common stock		(960	)		—			—			—			(960	)
Change in short term borrowings		—			—			694			—			694
Cash dividends paid		(764	)		(1,198	)		(1,484	)		2,682			(764	)
Change in advances—affiliates		1,724			—			981			(2,705	)		—
Other, net		(12	)		—			(22	)		—			(34	)
Cash used in financing activities		(743	)		(1,204	)		(362	)		(23	)		(2,332	)
Cash flows—investing activities:
Capital expenditures and nuclear fuel		(12	)		—			(2,285	)		—			(2,297	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			207			—			207
Investments in nuclear decommissioning trust fund securities		—			—			(223	)		—			(223	)
Change in advances—affiliates		—			(299	)		(2,433	)		2,732			—
Investment in collateral trust		533			—			(533	)		—			—
Other, net		2			(69	)		(284	)		—			(351	)
Cash provided by (used in) investing activities		523			(368	)		(5,551	)		2,732			(2,664	)
Cash flows—discontinued operations:
Operating activities		—			—			30			—			30
Financing activities		—			—			—			—			—
Investing activities		—			—			—			—			—
Cash provided by discontinued operations		—			—			30			—			30
Net change in cash and equivalents		—			—			(12	)		—			(12	)
Cash and cash equivalents—beginning balance		—			—			37			—			37
Cash and cash equivalents—ending balance	$	—		$	—		$	25		$	—		$	25

F-151

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2005

(millions of dollars)

	Predecessor
	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows—operating activities:
Net income	$	1,722		$	1,747		$	1,915		$	(3,662	)	$	1,722
Income (loss) from discontinued operations, net of tax		(10	)		—			5			—			(5	)
Extraordinary loss, net of tax		—			—			50			—			50
Cumulative effect of changes in accounting principal, net of tax		—			—			8			—			8
Income from continuing operations before extraordinary loss and cumulative change in accounting principles		1,712			1,747			1,978			(3,662	)		1,775
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Equity in earnings of subsidiaries		(1,931	)		(1,752	)		—			3,683			—
Depreciation and amortization		—			—			836			—			836
Deferred income tax expense—net		17			1			463			—			481
Impairments and other asset writedown charges		—			—			11			—			11
Net losses from unrealized mark-to-market valuations		—			—			18			—			18
Other, net		12			—			(69	)		(19	)		(76	)
Changes in operating assets and liabilities:
Margin deposits—net		—			—			61			—			61
Other		322			731			(126	)		(1,240	)		(313	)
Cash provided by operating activities		132			727			3,172			(1,238	)		2,793
Cash flows—financing activities:
Issuance of securities:
Long-term debt		—			—			180			—			180
Common stock		84			—			(1	)		—			83
Retirements/repurchases of securities:
Long-term debt		(106	)		(5	)		(264	)		—			(375	)
Preference stock		(300	)		(38	)		—			—			(338	)
Common stock		(1,137	)		—			—			38			(1,099	)
Change in short term borrowings		—			—			588			—			588
Cash dividends paid		(555	)		(528	)		(697	)		1,225			(555	)
Change in advances—affiliates		1,883			—			(1,441	)		(442	)		—
Other, net		(26	)		—			(21	)		—			(47	)
Cash used in financing activities		(157	)		(571	)		(1,656	)		821			(1,563	)
Cash flows—investing activities:
Capital expenditures and nuclear fuel		—			—			(1,104	)		—			(1,104	)
Dispositions of businesses		—			—			77			—			77
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			191			—			191
Investments in nuclear decommissioning trust fund securities		—			—			(206	)		—			(206	)
Change in advances—affiliates		—			(156	)		(261	)		417			—
Other, net		16			—			(12	)		—			4
Cash provided by (used in) investing activities		16			(156	)		(1,315	)		417			(1,038	)
Cash flows—discontinued operations:
Operating activities		(3	)		—			(262	)		—			(265	)
Financing activities		—			—			—			—			—
Investing activities		—			—			4			—			4
Cash provided by discontinued operations		(3	)		—			(258	)		—			(261	)
Net change in cash and equivalents		(12	)		—			(57	)		—			(69	)
Cash and cash equivalents—beginning balance		12			—			94			—			106
Cash and cash equivalents—ending balance	$	—		$	—		$	37		$	—		$	37

F-152

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at December 31, 2007

(millions of dollars)

	Successor
	Parent/ Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	32	$	—	$	249	$	—		$	281
Restricted cash		—		—		56		—			56
Advances to parent		378		1		—		(379	)		—
Trade accounts receivable—net		28		—		1,071		—			1,099
Income taxes receivable		—		44		366		(309	)		101
Accounts receivable from affiliates		—		82		29		(111	)		—
Notes receivable from affiliates		—		—		59		(59	)		—
Inventories		—		—		405		—			405
Commodity and other derivative contractual assets		3		—		1,126		—			1,129
Accumulated deferred income taxes		—		1		76		(68	)		9
Margin deposits related to commodity positions		—		—		513		—			513
Other current assets		253		—		123		—			376
Total current assets		694		128		4,073		(926	)		3,969
Restricted cash		—		—		1,296		—			1,296
Investments		15,157		13,860		749		(28,898	)		868
Property, plant and equipment—net		—		—		28,650		—			28,650
Notes receivable from affiliates		12		—		2,308		(2,320	)		—
Goodwill		—		—		22,954		—			22,954
Intangible assets—net		—		—		4,365		—			4,365
Regulatory assets—net		—		—		1,305		—			1,305
Commodity and other derivative contractual assets		—		—		244		—			244
Accumulated deferred income taxes		478		19		—		(497	)		—
Unamortized debt issuance costs and other noncurrent assets		144		132		986		(132	)		1,130
Assets held for sale		—		—		23		—			23
Total assets	$	16,485	$	14,139	$	66,953	$	(32,773	)	$	64,804
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings		—		—		1,718		—			1,718
Advances from affiliates		—		—		379		(379	)		—
Long-term debt due currently		200		7		306		—			513
Trade accounts payable		6		—		898		—			904
Accounts payable to affiliates		110		—		—		(110	)		—
Notes payable to affiliates		25		—		34		(59	)		—
Commodity and other derivative contractual liabilities		38		—		1,108		—			1,146
Margin deposits related to commodity positions		—		—		5		—			5
Accumulated deferred income taxes		69		—		—		(69	)		—
Accrued interest		114		87		422		(86	)		537
Other current liabilities		556		—		586		(263	)		879
Total current liabilities		1,118		94		5,456		(966	)		5,702
Accumulated deferred income taxes		—		—		7,161		(497	)		6,664
Investment tax credits		—		—		47		—			47
Commodity and other derivative contractual liabilities		—		—		2,453		—			2,453
Notes or other liabilities due affiliates		2,019		—		301		(2,320	)		—
Long-term debt, less amounts due currently		6,288		4,603		32,212		(4,500	)		38,603
Other noncurrent liabilities and deferred credits		375		—		4,275		—			4,650
Total liabilities		9,800		4,697		51,905		(8,283	)		58,119
Shareholders’ equity		6,685		9,442		15,048		(24,490	)		6,685
Total liabilities and shareholders’ equity	$	16,485	$	14,139	$	66,953	$	(32,773	)	$	64,804

F-153

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at December 31, 2006

(millions of dollars)

	Predecessor
	Parent/ Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—	$	25	$	—		$	25
Restricted cash		—		—		58		—			58
Advances to parent		—		584		1,818		(2,402	)		—
Trade accounts receivable—net		4		1		954		—			959
Income taxes receivable		165		—		—		(165	)		—
Accounts receivable from affiliates		—		146		—		(146	)		—
Notes receivable from affiliates		—		—		1,533		(1,533	)		—
Inventories		—		—		383		—			383
Commodity and other derivative contractual assets		2		—		2,192		—			2,194
Accumulated deferred income taxes		—		5		253		(5	)		253
Margin deposits related to commodity positions		—		—		7		—			7
Other current assets		9		—		169		—			178
Total current assets		180		736		7,392		(4,251	)		4,057
Restricted cash		—		—		258		—			258
Investments		12,457		9,954		682		(22,381	)		712
Property, plant and equipment—net		33		—		18,536		—			18,569
Notes receivable from affiliates		12		700		3,006		(3,718	)		—
Goodwill		—		—		542		—			542
Intangible assets—net		—		—		187		—			187
Regulatory assets—net		—		—		2,028		—			2,028
Commodity and other derivative contractual assets		11		—		473		—			484
Accumulated deferred income taxes		118		391		—		(509	)		—
Unamortized debt issuance costs and other noncurrent assets		150		—		229		—			379
Total assets	$	12,961	$	11,781	$	33,333	$	(30,859	)	$	27,216
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings		—		—		1,491		—			1,491
Advances from affiliates		2,402		—		—		(2,402	)		—
Long-term debt due currently		—		17		468		—			485
Trade accounts payable		18		—		1,075		—			1,093
Accounts payable to affiliates		102		—		44		(146	)		—
Notes payable to affiliates		1,500		—		33		(1,533	)		—
Commodity and other derivative contractual liabilities		21		—		1,516		—			1,537
Margin deposits related to commodity positions		—		—		681		—			681
Accumulated deferred income taxes		5		—		—		(5	)		—
Other current liabilities		236		21		948		(164	)		1,041
Total current liabilities		4,284		38		6,256		(4,250	)		6,328
Accumulated deferred income taxes		—		—		4,747		(509	)		4,238
Investment tax credits		—		—		363		—			363
Commodity and other derivative contractual liabilities		63		—		267		—			330
Notes or other liabilities due affiliates		2,714		700		305		(3,719	)		—
Long-term debt, less amounts due currently		3,643		124		6,864		—			10,631
Other noncurrent liabilities and deferred credits		117		—		3,069		—			3,186
Total liabilities		10,821		862		21,871		(8,478	)		25,076
Shareholders’ equity		2,140		10,919		11,462		(22,381	)		2,140
Total liabilities and shareholders’ equity	$	12,961	$	11,781	$	33,333	$	(30,859	)	$	27,216

F-154

ENERGY FUTURE HOLDINGS CORP.

Offers to Exchange

$2,000,000,000 aggregate principal amount of its 10.875% Senior Notes due 2017 and $2,500,000,000 aggregate principal amount of its 11.250%/12.000% Senior Toggle Notes due 2017, each of which have been registered under the Securities Act of 1933, as amended, for any and all of its outstanding 10.875% Senior Notes due 2017 and 11.250%/12.000% Senior Toggle Notes due 2017, respectively.

Until the date that is 90 days from the date of this prospectus, all dealers that effect transactions in these securities, whether or not participating in the exchange offers, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters with respect to their unsold allotments or subscriptions.

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20. Indemnification of Directors and Officers.

EFH Corp. is a corporation formed under the Texas Business Organizations Code (the “TBOC”).

TBOC

Section 8.051 of the TBOC states that: (a) An enterprise shall indemnify a governing person, former governing person, or delegate against reasonable expenses actually incurred by the person in connection with a proceeding in which the person is a respondent because the person is or was a governing person or delegate if the person is wholly successful, on the merits or otherwise, in the defense of the proceeding. (b) A court that determines, in a suit for indemnification, that a governing person, former governing person, or delegate is entitled to indemnification under this section shall order indemnification and award to the person the expenses incurred in securing the indemnification.

Section 8.052 of the TBOC states as follows:

(a) On application of a governing person, former governing person, or delegate and after notice is provided as required by the court, a court may order an enterprise to indemnify the person to the extent the court determines that the person is fairly and reasonably entitled to indemnification in view of all the relevant circumstances.

(b) This section applies without regard to whether the governing person, former governing person, or delegate applying to the court satisfies the requirements of Section 8.101 or has been found liable: (1) to the enterprise; or (2) because the person improperly received a personal benefit, without regard to whether the benefit resulted from an action taken in the person’s official capacity.

(c) The indemnification ordered by the court under this section is limited to reasonable expenses if the governing person, former governing person, or delegate is found liable: (1) to the enterprise; or (2) because the person improperly received a personal benefit, without regard to whether the benefit resulted from an action taken in the person’s official capacity.

Section 8.101 of the TBOC states as follows:

(a) An enterprise may indemnify a governing person, former governing person, or delegate who was, is, or is threatened to be made a respondent in a proceeding to the extent permitted by Section 8.102 if it is determined in accordance with Section 8.103 that: (1) the person: (A) acted in good faith; (B) reasonably believed: (i) in the case of conduct in the person’s official capacity, that the person’s conduct was in the enterprise’s best interests; and (ii) in any other case, that the person’s conduct was not opposed to the enterprise’s best interests; and (C) in the case of a criminal proceeding, did not have a reasonable cause to believe the person’s conduct was unlawful; (2) with respect to expenses, the amount of expenses other than a judgment is reasonable; and (3) indemnification should be paid.

(b) Action taken or omitted by a governing person or delegate with respect to an employee benefit plan in the performance of the person’s duties for a purpose reasonably believed by the person to be in the interest of the participants and beneficiaries of the plan is for a purpose that is not opposed to the best interests of the enterprise.

(c) Action taken or omitted by a delegate to another enterprise for a purpose reasonably believed by the delegate to be in the interest of the other enterprise or its owners or members is for a purpose that is not opposed to the best interests of the enterprise.

(d) A person does not fail to meet the standard under Subsection (a)(1) solely because of the termination of a proceeding by: (1) judgment; (2) order; (3) settlement; (4) conviction; or (5) a plea of nolo contendere or its equivalent.

II-1

Section 8.102 of the TBOC states as follows:

(a) Subject to Subsection (b), an enterprise may indemnify a governing person, former governing person, or delegate against: (1) a judgment; and (2) expenses, other than a judgment, that are reasonable and actually incurred by the person in connection with a proceeding.

(b) Indemnification under this subchapter of a person who is found liable to the enterprise or is found liable because the person improperly received a personal benefit: (1) is limited to reasonable expenses actually incurred by the person in connection with the proceeding; (2) does not include a judgment, a penalty, a fine, and an excise or similar tax, including an excise tax assessed against the person with respect to an employee benefit plan; and (3) may not be made in relation to a proceeding in which the person has been found liable for: (A) willful or intentional misconduct in the performance of the person’s duty to the enterprise; (B) breach of the person’s duty of loyalty owed to the enterprise; or (C) an act or omission not committed in good faith that constitutes a breach of a duty owed by the person to the enterprise.

(c) A governing person, former governing person, or delegate is considered to have been found liable in relation to a claim, issue, or matter only if the liability is established by an order, including a judgment or decree of a court, and all appeals of the order are exhausted or foreclosed by law.

Restated Certificate of Formation of EFH Corp.

Article IX of the Restated Certificate of Formation of EFH Corp. provides as follows:

1. Right to Indemnification. Subject to the limitations and conditions as provided in this Article IX, each person who was or is made a party or is threatened to be made a party to or is involved in any threatened, pending or completed action or other proceeding, whether civil, criminal, administrative, arbitrative or investigative, or any appeal in such a proceeding or any inquiry or investigation that could lead to such a proceeding (hereinafter a “proceeding”), by reason of the fact that he or she, or a person of whom he or she is the legal representative, is or was a director or officer of the Corporation or while a director or officer of the Corporation is or was serving at the request of the Corporation as a director, officer, partner, venturer, proprietor, trustee, employee, agent, or similar functionary of another foreign or domestic corporation, limited liability company, partnership, joint venture, sole proprietorship, trust, employee benefit plan or other enterprise shall be indemnified by the Corporation to the fullest extent permitted by the TBOC, as the same exists or may hereafter be amended against judgments, penalties (including excise and similar taxes and punitive damages), fines, settlements and reasonable expenses (including, without limitation, attorneys’ fees) actually incurred by such person in connection with such proceeding, and indemnification under this Article IX shall continue as to a person who has ceased to serve in the capacity which initially entitled such person to indemnity hereunder. The rights granted pursuant to this Article IX shall be deemed contract rights, and no amendment, modification or repeal of this Article IX shall have the effect of limiting or denying any such rights with respect to actions taken or proceedings arising prior to any such amendment, modification or repeal. It is expressly acknowledged that the indemnification provided in this Article IX could involve indemnification for negligence or under theories of strict liability.

2. Advancement of Expenses. The right to indemnification conferred in this Article IX shall include the right to be paid or reimbursed by the Corporation the reasonable expenses incurred by a person of the type entitled to be indemnified above who was, is or is threatened to be made a named defendant or respondent in a proceeding in advance of the final disposition of the proceeding and without any determination as to the person’s ultimate entitlement to indemnification; provided, however, that the payment of such expenses incurred by any such person in advance of the final disposition of a proceeding shall be made only upon delivery to the Corporation of a written affirmation by such indemnified person of his or her good faith belief that he or she has met the standard of conduct necessary for indemnification under this Article IX and a written undertaking, by or on behalf of such person, to repay all amounts so advanced if it shall ultimately be determined that such indemnified person is not entitled to be indemnified under this Article IX or if such indemnification is prohibited by applicable law.

II-2

3. Indemnification of Employees and Agents. The Corporation, by adoption of a resolution by the board of directors or a duly appointed committee of the board of directors, may indemnify and advance expenses to an employee or agent of the Corporation to the same extent and subject to the same conditions under which it may indemnify and advance expenses to directors and officers under this Article IX; and the Corporation, by adoption of a resolution by the board of directors or a duly appointed committee of the board of directors, may indemnify and advance expenses to persons who are not or were not directors, officers, employees or agents of the Corporation but who are or were serving at the request of the Corporation as a director, officer, manager, member, partner, venturer, proprietor, trustee, employee, agent or similar functionary of another foreign or domestic corporation, limited liability company, partnership, joint venture, sole proprietorship, trust, employee benefit plan or other enterprise against any liability asserted against him or her and incurred by him or her in such a capacity or arising out of his or her status as such a person to the same extent that it may indemnify and advance expenses to directors and officers under this Article IX.

4. Appearance as a Witness. Notwithstanding any other provision of this Article IX, the Corporation may pay or reimburse expenses incurred by a director, officer, employee, agent or other person in connection with his or her appearance as a witness or other participation in a proceeding at a time when he or she is not a named defendant or respondent in the proceeding.

5. Nonexclusivity of Rights. The right to indemnification and the advancement and payment of expenses conferred in this Article IX shall not be exclusive of any other right which a director or officer or other person indemnified pursuant to this Article IX may have or hereafter acquire under any law (common or statutory), provision of this certificate of formation or the bylaws of the Corporation, agreement, vote of shareholders or disinterested directors or otherwise.

6. Insurance. The Corporation may purchase, procure, establish and maintain, at its expense, insurance or another arrangement to indemnify or hold harmless, to protect itself and any person who is or was serving as a director, officer, employee or agent of the Corporation or is or was serving at the request of the Corporation as a director, officer, manager, member, partner, venturer, proprietor, trustee, employee, agent or similar functionary of another foreign or domestic corporation, limited liability company, partnership, joint venture, proprietorship, employee benefit plan, trust or other enterprise against any expense, liability or loss, whether or not the Corporation would have the power to indemnify such person against such expense, liability or loss under this Article IX.

7. Savings Clause. If this Article IX or any portion hereof shall be invalidated on any ground by any court of competent jurisdiction, then the Corporation shall nevertheless indemnify and hold harmless each director, officer or any other person indemnified pursuant to this Article IX as to costs, charges and expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement with respect to any action, suit or proceeding, whether civil, criminal, administrative or investigative to the full extent permitted by any applicable portion of this Article IX that shall not have been invalidated and to the fullest extent permitted by applicable law.

For purposes of this Article IX, the term “Corporation” shall include any predecessor of the Corporation and any constituent corporation (including any constituent of a constituent) absorbed by the Corporation in a consolidation or merger; the term “other enterprise” shall include any corporation, limited liability company, partnership, joint venture, trust or employee benefit plan; service “at the request of the Corporation” shall include service as a director, officer, manager, member or employee of the Corporation which imposes duties on, or involves services by, such director, officer, manager, member or employee with respect to an employee benefit plan, its participants or beneficiaries; any excise taxes assessed on a person with respect to an employee benefit plan shall be deemed to be indemnifiable expenses; and action by a person with respect to an employee benefit plan which such person reasonably believes to be in the interest of the participants and beneficiaries of such plan shall be deemed to be action not opposed to the best interests of the Corporation.

II-3

Article X of the Restated Certificate of Formation of EFH Corp. provides as follows:

A director of the Corporation shall not be liable to the Corporation or its shareholders for monetary damages for any act or omission in the director’s capacity as a director, except that this provision does not eliminate or limit the liability of a director to the extent the director is found liable under applicable law for:

(a) a breach of the director’s duty of loyalty to the Corporation or its shareholders;

(b) an act or omission not in good faith that constitutes a breach of duty of the director to the Corporation or that involves intentional misconduct or a knowing violation of the law;

(c) a transaction from which the director received an improper benefit, regardless of whether the benefit resulted from an action taken within the scope of the director’s duties; or

(d) an act or omission for which the liability of the director is expressly provided for by an applicable statute.

If the TBOC is amended to authorize action further eliminating or limiting the personal liability of directors, then the liability of a director of the Corporation shall be eliminated or limited to the fullest extent permitted by the TBOC as so amended. Any repeal or modification of this Article X shall not adversely affect any right of protection of a director of the Corporation existing at the time of such repeal or modification.

Amended and Restated Bylaws of EFH Corp.

Section 15 of the Amended and Restated Bylaws of EFH Corp. provides as follows:

Without further specific approval of the shareholders of the Corporation, the Corporation may purchase, enter into, maintain or provide insurance, indemnification or other arrangements for the benefit of any person who is or was a director, officer, employee or agent of the Corporation or is or was serving another entity at the request of the Corporation as a director, officer, manager, member, partner, venturer, proprietor, trustee, employee, agent or similar functionary, to the fullest extent permitted by the laws of the State of Texas, including without limitation Chapter 8 of the Texas Business Organizations Code or any successor provision, against any liability asserted against or incurred by any such person in any such capacity or arising out of such person’s service in such capacity whether or not the Corporation would otherwise have the power to indemnify against any such liability under the Texas Business Organizations Code. If the laws of the State of Texas are amended to authorize the purchase, entering into, maintaining or providing of insurance, indemnification or other arrangements in the nature of those permitted hereby to a greater extent than presently permitted, then the Corporation shall have the power and authority to purchase, enter into, maintain and provide any additional arrangements in such regard as shall be permitted from time to time by the laws of the State of Texas without further approval of the shareholders of the Corporation. No repeal or modification of such laws or this Section 15 shall adversely affect any such arrangement or right to indemnification existing at the time of such repeal or modification.

Certain Other Arrangements

In addition to indemnification by EFH Corp. pursuant to its Restated Certificate of Formation and its Amended and Restated Bylaws, the directors, officers, managers, members, employees, agents and similar functionaries of the co-registrants are generally also entitled to indemnification and exculpation for certain monetary damages to the extent provided in the co-registrants’ organizational documents or under the statutes under which the co-registrants are organized.

EFH Corp. maintains a directors’ and officers’ liability insurance policy that covers the directors and officers of each of the registrants in amounts that EFH Corp. believes are customary for companies similarly situated, including for liabilities in connection with the registration, offering and exchange of the notes.

II-4

In addition, pursuant to the Management Agreement entered into with the members of the Sponsor Group and their affiliates, EFH Corp. has agreed to customary exculpation and indemnification provisions for the benefit of the members of the Sponsor Group, their affiliates, directors, officers and certain other persons. See “Certain Relationships and Related Party Transactions—Management Services Agreement” in the prospectus included in this registration statement.

Item 21. Exhibits and Financial Statement Schedules.

(a) Exhibits

Exhibits	Previously Filed* With File Number	As Exhibit
(2)	Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
2(a)	1-12833 Form 8-K (filed February 26, 2007)	2.1	—	Agreement and Plan of Merger, dated February 25, 2007, by and among Energy Future Holdings Corp. (formerly known as TXU Corp.), Texas Energy Future Holdings Limited Partnership and Texas Energy Future Merger Sub Corp
(3(i))	Articles of Incorporation
3(a)	1-12833 Form 8-K (filed October 11, 2007)	3.1	—	Restated Certificate of Formation of Energy Future Holdings Corp.
3(b)	333 - 153529 Form S-4 (filed September 17, 2008)	3(b)	—	Second Amended and Restated Articles of Incorporation of Energy Future Competitive Holdings Company (formerly known as TXU US Holdings Company)
3(c)	333 - 153529 Form S-4 (filed September 17, 2008)	3(c)	—	Certificate of Formation of Energy Future Intermediate Holding Company LLC (formerly TXU Asset Services Company LLC and InfrastuX Energy Services BPL LLC), as amended
(3(ii))	By-laws
3(d)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	3(a)	—	Amended and Restated Bylaws of Energy Future Holdings Corp.
3(e)	333 - 153529 Form S-4 (filed September 17, 2008)	3(e)	—	Restated Bylaws of Energy Future Competitive Holdings Company (formerly known as TXU US Holdings Company)
3(f)	333 - 153529 Form S-4 (filed September 17, 2008)	3(f)	—	Amended and Restated Limited Liability Company Agreement of Energy Future Intermediate Holding Company LLC

II-5

Exhibits	Previously Filed* With File Number	As Exhibit
(4)	Instruments Defining the Rights of Security Holders, Including Indentures**
	Energy Future Holdings Corp.
4(a)	1-12833 Form 10-K (1997) (filed March 27, 1998)	4(c)	—	Indenture (For Unsecured Debt Securities Series P), dated as of November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon (formerly known as The Bank of New York). Energy Future Holdings Corp.’s Indentures for its Series Q and R Senior Notes are not being filed as they are substantially similar to this Indenture
4(b)	1-12833 Form 10-K (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(c)	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(d)	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
4(e)	1-12833 Form 8-K (filed October 31, 2007)	4.1	—	Indenture, dated as of October 31, 2007, relating to Energy Future Holdings Corp.’s 10.875% Senior Notes due 2017 and 11.250%/12.000% Senior Toggle Notes due 2017
4(f)	333 - 153529 Form S-4 (filed September 17, 2008)	4(f)	—	Registration Rights Agreement, dated as of October 31, 2007, among Energy Future Holdings Corp., the subsidiary guarantors party thereto and the initial purchasers party thereto, as representatives of all of the initial purchasers.
	Oncor Electric Delivery Company LLC
4(g)	333-100240 Form S-4 (filed October 2, 2002)	4(a)	—	Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC (formerly Oncor Electric Delivery Company, formerly known as TXU Electric Delivery Company) and The Bank of New York Mellon, as Trustee
4(h)	1-12833 Form 8-K (filed October 31, 2005)	10.1	—	Supplemental Indenture No. 1, dated October 25, 2005, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon
4(i)	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(j)	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

II-6

Exhibits	Previously Filed* With File Number	As Exhibit
4(k)	333-100242 Form S-4 (filed October 2, 2002)	4(a)	—	Indenture (for Unsecured Debt Securities), dated as of August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon, as Trustee
4(l)	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
4(m)	333-100242 Form 8-K (filed September 9, 2008)	4.1	—	Officer’s Certificate, dated September 8, 2008, establishing the terms of Oncor’s 5.95% Senior Secured Notes due 2013, 6.80% Senior Secured Notes due 2018 and 7.50% Senior Secured Notes due 2038
4(n)	333-100242 Form 8-K (filed September 9, 2008)	4.2		Registration Rights Agreement, dated September 8, 2008, among Oncor and the representatives of the several initial purchasers of Oncor’s 5.95% Senior Secured Notes due 2013, 6.80% Senior Secured Notes due 2018 and 7.50% Senior Secured Notes due 2038
	Texas Competitive Electric Holdings Company LLC
4(o)	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(p)	333 - 153529 Form S-4 (filed September 17, 2008)	4(p)	—	Registration Rights Agreement, dated as of October 31, 2007, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and the initial purchasers party thereto, as representative of all of the initial purchasers
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
4(r)	333 - 153529 Form S-4 (filed September 17, 2008)	4(r)	—	Registration Rights Agreement, dated as of December 6, 2007 among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and the initial purchasers party thereto, as representative of all of the initial purchasers
4(s)	333 - 153529 Form S-4 (filed September 17, 2008)	4(s)	—	Registration Rights Agreement, dated as of December 6, 2007 among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the guarantors party thereto and the initial purchasers party thereto, as representative of all of the initial purchasers
(5)	Opinion re Legality
5(a)	333 - 153529 Form S-4 (filed September 17, 2008)	5(a)	—	Opinion of Andrew M. Wright, Vice President and Associate General Counsel of EFH Corporate Services Company

II-7

Exhibits	Previously Filed* With File Number	As Exhibit
(10)	Material Contracts
	Management Contracts; Compensatory Plans, Contracts and Arrangements
10(a)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(a)	—	2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates
10(b)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(b)	—	Registration Rights Agreement by and among Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp. and the stockholders party thereto
10(c)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(c)	—	Summary of Consulting Arrangement, between Donald Evans and Energy Future Holdings Corp.
10(d)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(d)	—	Consulting Agreement, dated December 5, 2007, between James R. Huffines and Energy Future Holdings Corp.
10(e)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(e)	—	Consulting Agreement, dated December 5, 2007, between Lyndon Olson and Energy Future Holdings Corp.
10(f)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(f)	—	Energy Future Holdings Corp. Non-employee Director Compensation Arrangements
10(g)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(a)	—	Form of Stockholder’s Agreement (for Directors), by and among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and the stockholder party thereto
10(h)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(b)	—	Form of Sale Participation Agreement (for Directors), by and between Texas Energy Future Holdings Limited Partnership and the stockholder party thereto
10(i)	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

II-8

Exhibits	Previously Filed* With File Number	As Exhibit
10(j)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(h)	—	Amendment to EFH Deferred and Incentive Compensation Plan Trust Agreement, dated October 5, 2007
10(k)	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(l)			—	EFH Salary Deferral Program, as amended and restated, effective October 10, 2007
10(m)	1-12833 Form 8-K (filed May 23, 2005)	10.7	—	Energy Future Holdings Corp. 2005 Executive Severance Plan
10(n)			—	Amendment to the Energy Future Holdings Corp. 2005 Executive Severance Plan and Summary Description
10(o)	1-12833 Form 8-K (filed May 23, 2005)	10.6	—	Energy Future Holdings Corp. Executive Change in Control Policy
10(p)			—	Amendment to the Energy Future Holdings Corp. Executive Change in Control Policy
10(q)	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(r)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(n)	—	Amendment to the EFH Split Dollar Life Insurance Program, effective as of October 10, 2007
10(s)	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(t)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(p)	—	Employment Agreement, dated January 6, 2008, by and between John F. Young and Energy Future Holdings Corp.
10(u)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(e)	—	Form of Non-Qualified Stock Option Agreement (For Executive Officers)
10(v)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(q)	—	Energy Future Holdings Corp. Key Employee Non-Qualified Stock Option Agreement, dated as of February 1, 2008, by and between John F. Young and Energy Future Holdings Corp.

II-9

Exhibits	Previously Filed* With File Number	As Exhibit
10(w)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(f)	—	Form of Management Stockholder’s Agreement (For Executive Officers)
10(x)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(r)	—	Management Stockholder’s Agreement, dated as of February 1, 2008, by and among John F. Young, Texas Energy Future Holdings Limited Partnership and Energy Future Holdings Corp.
10(y)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(g)	—	Form of Sale Participation Agreement (For Executive Officers)
10(z)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(s)	—	Sale Participation Agreement, dated as of February 1, 2008, by and between John F. Young and Texas Energy Future Holdings Limited Partnership
10(aa)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(t)	—	Severance and Release Agreement, dated October 10, 2007, by and between C. John Wilder and Energy Future Holdings Corp.
10(bb)	1-12833 Form 10-K (2007) (filed March 31, 2008)	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(cc)	1-12833 Form 8-K (filed June 6, 2008)	10.1	—	Employment Agreement, dated as of July 1, 2008, by and between Paul M. Keglevic and Energy Future Holdings Corp.
10(dd)	1-12833 Form 10-Q (2004) (filed March 16, 2005)	10(l)	—	Employment Agreement, dated May 9, 2008, by and among David Campbell, Energy Future Holdings Corp. and Luminant Holding Company LLC
10(ee)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(y)	—	Additional Payment Agreement, dated October 10, 2007, by and among David Campbell, Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and Texas Competitive Electric Holdings Company LLC
10(ff)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(i)	—	Employment Agreement, dated May 9, 2008, by and among Michael Greene, Energy Future Holdings Corp. and Luminant Holding Company LLC

II-10

Exhibits	Previously Filed* With File Number	As Exhibit
10(gg)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(h)	—	Employment Agreement, dated May 9, 2008, by and between Rob Walters and Energy Future Holdings Corp.
10(hh)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(bb)	—	Severance and Release Agreement, dated March 31, 2008 by and between David P. Poole and Energy Future Holdings Corp.
10(ii)	1-12833 Form 10-K (2007) (filed March 31, 2008)	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(jj)	1-12833 Form 8-K (filed June 6, 2008)	10.2	—	Amended and Restated Employment Agreement, dated June 6, 2008, by and among Luminant Holding Company LLC, EFH Corp. and Michael McCall
10(kk)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(p)	—	Amended and Restated Employment Agreement, dated May 9, 2008, by and among James Burke, Energy Future Holdings Corp. and TXU Energy Retail Company LLC
10(ll)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ff)	—	Additional Payment Agreement, dated October 10, 2007, by and among James Burke, Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and Texas Competitive Electric Holdings Company LLC
10(mm)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(l)	—	Consulting Agreement, effective as of November 1, 2007, between T.L. Baker and Energy Future Holdings Corp.
10(nn)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(m)	—	Restricted Stock Award Agreement, dated April 4, 2008 by and between T.L. Baker and Energy Future Holdings Corp.
10(oo)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(n)	—	Stockholder Agreement, dated April 4, 2008 by and among T.L. Baker, Energy Future Holdings Corp. and Texas Energy Future Holdings Limited Partnership

II-11

Exhibits	Previously Filed* With File Number	As Exhibit
10(pp)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(o)	—	Sale Participation Agreement, dated April 4, 2008, by and between T.L. Baker and Texas Energy Future Holdings Limited Partnership
10(qq)	1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008)	10(k)	—	Employment Agreement, dated May 9, 2008, by and among Charles R. Enze, Energy Future Holdings Corp. and Luminant Holding Company LLC
10(rr)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(a)	—	Employment Agreement, dated May 23, 2008, by and between M. Rizwan Chand and Energy Future Holdings Corp.
10(ss)	1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008)	10(d)	—	Employment Agreement, dated July 7, 2008, by and between Luminant Holding Company LLC, Energy Future Holdings Corp. and Mark Allen McFarland
10(tt)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(nn)	—	Deferred Share Agreement, dated October 9, 2007, by and between James Burke and Texas Energy Future Holdings Limited Partnership
10(uu)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(oo)	—	Deferred Share Agreement, dated October 9, 2007 by and between Charles Enze and Texas Energy Future Holdings Limited Partnership
10(vv)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(pp)	—	Deferred Share Agreement, dated October 9, 2007, by and between Michael McCall and Texas Energy Future Holdings Limited Partnership
10(ww)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(qq)	—	Deferred Share Agreement, dated October 9, 2007, by and between Michael Greene and Texas Energy Future Holdings Limited Partnership

II-12

Exhibits	Previously Filed* With File Number	As Exhibit
	Credit Agreements
10(xx)	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(yy)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ss)	—	Guarantee Agreement, dated as of October 10, 2007, by the guarantors party thereto in favor of Citibank, N.A., as collateral agent for the benefit of the secured parties under the $24,500,000,000 Credit Agreement
10(zz)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(tt)	—	Pledge Agreement, dated as of October 10, 2007, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary pledgors party thereto, and Citibank, N.A., as collateral agent for the benefit of the secured parties under the $24,500,000,000 Credit Agreement
10(aaa)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(uu)	—	Security Agreement, dated as of October 10, 2007, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary grantors party thereto, and Citibank, N.A., as collateral agent for the benefit of the secured parties under the $24,500,000,000 Credit Agreement
10(bbb)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(vv)	—	Form of Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as Trustee, for the benefit of Citibank, N.A., as Beneficiary
10(ccc)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ww)	—	Collateral Agency and Intercreditor Agreement, dated as of October 10, 2007, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary guarantors party thereto, Citibank, N.A., as administrative agent and collateral agent, Lehman Brothers Commodity Services Inc., J. Aron & Company, Morgan Stanley Capital Group Inc., Citigroup energy Inc., and each other secured commodity hedge counterparty from time to time party thereto, and any other person that becomes a secured party pursuant thereto

II-13

Exhibits	Previously Filed* With File Number	As Exhibit
10(ddd)	1-12833 Form 10-K (2007) (filed March 31, 2008)	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(eee)	1-12833 Form 10-K (2007) (filed March 31, 2008)	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(fff)	1-12833 Form 10-K (2007) (filed March 31, 2008)	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(ggg)	1-12833 Form 10-K (2007) (filed March 31, 2008)	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
10(hhh)	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

II-14

Exhibits	Previously Filed* With File Number	As Exhibit
	Other Material Contracts
10(iii)	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(jjj)	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(kkk)	333-100240 Form 8-K (filed August 13, 2008)	10.1	—	Contribution and Subscription Agreement, dated as of August 12, 2008, by and between Oncor and Texas Transmission Investment LLC
10(lll)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(eee)	—	Stipulation as approved by the PUC in Docket No. 34077
10(mmm)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(fff)	—	Amendment to Stipulation Regarding Section 1, Paragraph 35 and Exhibit B in Docket No. 34077
10(nnn)	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(ooo)	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(ppp)	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(qqq)	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)

II-15

Exhibits	Previously Filed* With File Number	As Exhibit
10(rrr)	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(sss)	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(ttt)	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)
10(uuu)	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(vvv)	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(www)	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(xxx)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(sss)	—	ISDA Master Agreement, dated as of October 25, 2007, between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(yyy)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(ttt)	—	Schedule to the ISDA Master Agreement, dated as of October 25, 2007, between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.
10(zzz)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(uuu)	—	Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P.

II-16

Exhibits	Previously Filed* With File Number	As Exhibit
10(aaaa)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(vvv)	—	ISDA Master Agreement, dated as of October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International
10(bbbb)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(www)	—	Schedule to the ISDA Master Agreement, dated as of October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International
10(cccc)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(xxx)	—	Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Credit Suisse International
10(dddd)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(yyy)	—	Management Agreement, dated as of October 10, 2007, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership, Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P., Goldman, Sachs & Co. and Lehman Brothers Inc.
10(eeee)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(zzz)	—	Tax Sharing Agreement, dated as of October 10, 2007, among Energy Future Holdings Corp., Oncor Electric Delivery Company LLC and Oncor Electric Delivery Holdings Company LLC
10(ffff)	333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2007)	3(a)	—	Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Company LLC, dated as of November 5, 2008
10(gggg)	1-12833 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008)	10(g)	—	Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Holdings Company LLC, dated as of November 5, 2008
10(hhhh)	333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008)	4(c)	—	Investor Rights Agreement, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp.
10(iiii)	333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008)	4(d)	—	Registration Rights Agreement of Oncor Electric Delivery Company LLC, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp.

II-17

Exhibits	Previously Filed* With File Number	As Exhibit
10(jjjj)	333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008)	10(b)	—	Amended and Restated Tax Sharing Agreement, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Oncor Management Investment LLC, Texas Transmission Investment LLC, Energy Future Intermediate Holding Company LLC and Energy Future Holdings Corp.
10(kkkk)	1-12833 Form 10-K (2007) (filed March 31, 2008)	10(cccc)	—	Indemnification Agreement, dated as of October 10, 2007 among Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp., Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and Goldman Sachs & Co.
(12)	Statement Regarding Computation of Ratios
12(a)	333-153529 Amendment No. 1 to Form S-4 (filed November 26, 2008)		—	Computation of Ratio of Earnings to Fixed Charges, and Ratio of Earnings to Combined Fixed Charges and Preference Dividends
(15)	Letter re Unaudited Interim Financial Information
15(a)			—	Letter of Deloitte & Touche LLP, an independent registered public accounting firm
(21)	Subsidiaries of the Registrant
21(a)	333-153529 Form S-4 (filed September 17, 2008)	21(a)	—	Subsidiaries of Energy Future Holdings Corp.
(23)	Consents of Experts and Counsel
23(a)			—	Consent of Andrew M. Wright (included as part of the opinion filed as Exhibit 5(a) hereto)
23(b)			—	Consent of Deloitte & Touche LLP, an independent registered public accounting firm
(24)	Power of Attorney
24(a)			—	Powers of Attorney (included in signature pages of this Registration Statement)
(25)	Statement of Eligibility of Trustee
25(a)	333-153529 Form S-4 (filed September 17, 2008)	25(a)	—	Form T-1 Statement of Eligibility under the Trust Indenture Act of 1939 of The Bank of New York Mellon with respect to the Indenture governing the 10.875% Senior Notes due 2017 and Guarantees thereof
25(b)	333-153529 Form S-4 (filed September 17, 2008)	25(b)	—	Form T-1 Statement of Eligibility under the Trust Indenture Act of 1939 of The Bank of New York Mellon with respect to the Indenture governing the 11.250%/12.000% Senior Toggle Notes due 2017 and Guarantees thereof

II-18

Exhibits	Previously Filed* With File Number	As Exhibit
(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)	333-153529 Form S-4 (filed September 17, 2008)	99(b)	—	Form of Letter of Transmittal
99(c)	333-153529 Form S-4 (filed September 17, 2008)	99(c)	—	Form of Letter to Brokers, Dealers, Commercial Banks, Trust Companies and Other Nominees
99(d)	333-153529 Form S-4 (filed September 17, 2008)	99(d)	—	Form of Letter to Clients
99(e)	333-153529 Form S-4 (filed September 17, 2008)	99(e)	—	Form of Notice of Guaranteed Delivery

* 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.

II-19

(b) Financial Statement Schedules

Schedule I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

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 (“EFH Corp.”) 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) and have issued our report thereon dated March 31, 2008 (September 17, 2008 as to (1) the effects of the adoption of FASB Staff Position No. FIN 39-1 and the effects of the reclassification of results of EFH Corp.’s commodity hedging and trading activities as described in Note 1, and (2) Note 29) (included elsewhere in this registration statement). Our audits also included the financial statement schedule listed in Item 21 of this registration statement. This financial statement schedule is the responsibility of EFH Corp.’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Dallas, Texas

March 31, 2008

(September 17, 2008 as to Note 1)

II-20

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		(53	)		(235	)		(214	)		(120	)
Equity earnings (loss) of subsidiaries		(1,161	)		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.

II-21

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		1,161			(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		724			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.

II-22

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.

II-23

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.

Subsequent to the original filing of the EFH Corp. 2007 Form 10-K on March 31, 2008, in connection with the preparation of the condensed parent-only financial information herein, management identified that previously reported equity earnings (loss) of certain subsidiaries had been incorrectly presented on a pre-tax basis. The following table presents the related amounts previously reported and as corrected:

	Successor
	As Previously Reported			As Corrected
	Period from October 11, 2007 through December 31, 2007			Period from October 11, 2007 through December 31, 2007
Condensed Statements of Consolidated Income (Loss):
Income tax benefit	$	(533	)	$	(53	)
Equity earnings (loss) of subsidiaries		(1,641	)		(1,161	)
Net income (loss)		(1,360	)		(1,360	)
Condensed Statements of Cash Flows:
Equity in (earnings) losses of subsidiaries		1,641			1,161
Net change in operating assets and liabilities		244			724
Cash provided by operating activities from continuing operations		170			170

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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.

(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

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

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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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Item 22. Undertakings.

(a) Each of the undersigned registrants hereby undertakes:

(1) to file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) to include any prospectus required by Section 10(a)(3) of the Securities Act;

(ii) to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more that a 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

(iii) to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(2) that, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof;

(3) to remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering;

(4) that, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, if the registrants are subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness; provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use; and

(5) that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(ii) any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(iii) the portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

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(iv) any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

(b) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(c) Each of the undersigned registrants hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Item 4, 10(b), 11 or 13 of Form S-4 within one business day of receipt of such request and to send the incorporated documents by first class mail or equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

(d) Each of the undersigned registrants hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Dallas, State of Texas, on December 23, 2008.

ENERGY FUTURE HOLDINGS CORP.
By:	/s/    PAUL M. KEGLEVIC
Name:	Paul M. Keglevic
Title:	Executive Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
* John F. Young	President and Chief Executive Officer and Director	December 23, 2008
/s/    PAUL M. KEGLEVIC         Paul M. Keglevic	Executive Vice President and Chief Financial Officer	December 23, 2008
/s/    STANLEY J. SZLAUDERBACH         Stanley J. Szlauderbach	Senior Vice President and Controller (Principal Accounting Officer)	December 23, 2008

*By:	/s/    PAUL M. KEGLEVIC
	Paul M. Keglevic, as attorney-in-fact

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Signature	Title	Date
* Donald L. Evans	Chairman	December 23, 2008
* Arcilia C. Acosta	Director	December 23, 2008
* David Bonderman	Director	December 23, 2008
Thomas D. Ferguson	Director
* Frederick M. Goltz	Director	December 23, 2008
* James R. Huffines	Director	December 23, 2008
* Scott Lebovitz	Director	December 23, 2008
* Jeffrey Liaw	Director	December 23, 2008
* Marc S. Lipschultz	Director	December 23, 2008
* Michael MacDougall	Director	December 23, 2008
* Lyndon L. Olson, Jr.	Director	December 23, 2008
* Kenneth Pontarelli	Director	December 23, 2008
* William K. Reilly	Director	December 23, 2008
* Jonathan D. Smidt	Director	December 23, 2008
* Kneeland Youngblood	Director	December 23, 2008

*By:	/s/    PAUL M. KEGLEVIC
	Paul M. Keglevic, as attorney-in-fact

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Dallas, State of Texas, on December 23, 2008.

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY
By:	/s/    PAUL M. KEGLEVIC
Name:	Paul M. Keglevic
Title:	Executive Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
* John F. Young	President and Chief Executive Officer	December 23, 2008
/s/    PAUL M. KEGLEVIC         Paul M. Keglevic	Executive Vice President and Chief Financial Officer	December 23, 2008
/s/    STANLEY J. SZLAUDERBACH         Stanley J. Szlauderbach	Senior Vice President and Controller (Principal Accounting Officer)	December 23, 2008
* Frederick M. Goltz	Director	December 23, 2008
* Scott Lebovitz	Director	December 23, 2008
* Michael MacDougall	Director	December 23, 2008

*By:	/s/    PAUL M. KEGLEVIC
	Paul M. Keglevic, as attorney-in-fact

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Dallas, State of Texas, on December 23, 2008.

ENERGY FUTURE INTERMEDIATE HOLDING COMPANY LLC
By:	/s/    PAUL M. KEGLEVIC
Name:	Paul M. Keglevic
Title:	Executive Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
* John F. Young	President and Chief Executive Officer and Manager	December 23, 2008
/s/    PAUL M. KEGLEVIC         Paul M. Keglevic	Executive Vice President and Chief Financial Officer and Manager	December 23, 2008
/s/    STANLEY J. SZLAUDERBACH         Stanley J. Szlauderbach	Senior Vice President and Controller (Principal Accounting Officer)	December 23, 2008
* Jeffrey Liaw	Manager	December 23, 2008
* Marc S. Lipschultz	Manager	December 23, 2008

*By:	/s/    PAUL M. KEGLEVIC
	Paul M. Keglevic, as attorney-in-fact

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