Energy Future Competitive 424B3 Prospectus supplement

Filed Pursuant to Rule 424(b)(3)
Registration No. 333-171253

PROSPECTUS

ENERGY FUTURE HOLDINGS CORP.

Offer to Exchange

$1,060,757,000 aggregate principal amount of its 10.000% Senior Secured Notes due 2020 (the “exchange notes”), which have been registered under the Securities Act of 1933, as amended (the “Securities Act”), for any and all of its outstanding 10.000% Senior Secured Notes due 2020 (the “outstanding notes”) (the “exchange offer”).

We are conducting the exchange offer 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 Offer

• We will exchange all outstanding notes that are validly tendered and not validly withdrawn for an equal principal amount of exchange notes that are freely tradable.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

• The exchange offer expires at 11:59 p.m., New York City time, on March 1, 2011, unless extended. We do not currently intend to extend the expiration date.

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

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

Results of the Exchange Offer

• 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 offer, 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 offer 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 180 days after the consummation of the exchange offer, 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 15 for a discussion of certain risks that you should consider before participating in the exchange offer.

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 offer 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 February 1, 2011.

This prospectus is part of a registration statement that we have filed with the Securities and Exchange Commission (the “SEC”). You should read this prospectus together with the registration statement, the exhibits thereto and the additional information described under the heading “Available Information.”

EFH Corp. has not authorized any person (including any dealer, salesperson or broker) to provide you with any information or to make any representation other than as contained in this prospectus. EFH Corp. does not take any responsibility for, and can provide no assurance as to the reliability of, any information that others may give you. The information included in this prospectus is accurate as of the date of this prospectus. You should not assume that the information included in this prospectus is accurate as of any other date.

The exchange offer is being made on the basis of this prospectus and the letter of transmittal and is subject to the terms described in this prospectus and the letter of transmittal. This prospectus does not constitute an offer to participate in the exchange offer to any person in any jurisdiction in which it would be unlawful to make the exchange offer. Any decision to participate in the exchange offer must be based on the information included in this prospectus. In making an investment decision, holders must rely on their own examination of EFH Corp. and the terms of the exchange offer and the exchange notes, including the merits and risks involved. Holders should not construe anything in this prospectus and letter of transmittal as legal, investment, business or tax advice. Each holder should consult its advisors as needed to make its investment decision and to determine whether it is legally permitted to participate in the exchange offer under applicable laws or regulations.

This prospectus contains summaries believed to be accurate with respect to certain documents, but reference is made to the actual documents themselves for complete information. All such summaries are qualified in their entirety by such reference. Copies of documents referred to in this prospectus will be made available to holders in the exchange offer at no cost. See “Available Information.”

You should not rely on or assume the accuracy of any representation or warranty in any agreement that we have filed as an exhibit to any document that we have publicly filed or that we may otherwise publicly file in the future because such representation or warranty may be subject to exceptions and qualifications contained in separate disclosure schedules, may have been included in such agreement for the purpose of allocating risk between the parties to the particular transaction, and may no longer continue to be true as of any given date.

TABLE OF CONTENTS

	Page
Industry and Market Information		iii
Available Information		iii
Forward-Looking Statements		iv
Prospectus Summary		1
Risk Factors		15
Use of Proceeds		44
Capitalization		45
Selected Historical Consolidated Financial Data for EFH Corp. and Its Subsidiaries		47
Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010		51
Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Year Ended December 31, 2009		90
Our Businesses		152
Executive Compensation		183
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		209
Certain Relationships and Related Party Transactions		212
The Exchange Offer		217

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Description of the Notes	225
Certain United States Federal Income Tax Consequences	313
Certain ERISA Considerations	314
Plan of Distribution	316
Legal Matters	317
Experts	317
Glossary	318
Index to Consolidated Financial Statements

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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 the Electric Reliability Council of Texas (“ERCOT”), the Public Utility Commission of Texas (the “PUCT”), and the New York Mercantile Exchange. We did not commission any of these publications or reports. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data and make no representation as to the accuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions regarding general economic growth are used in preparing the forecasts included in this prospectus. Similarly, while we believe that such internal and external research is reliable, it has not been verified by any independent sources, and we make no assurances that the predictions contained therein are accurate.

AVAILABLE INFORMATION

EFH Corp. files annual, quarterly and current reports and other information with the SEC. You may read and copy any document EFH Corp. has filed 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. These materials do not form part of this prospectus.

You may request a copy of any of our filings with the SEC, or any of the agreements or other documents that constitute exhibits to those filings, at no cost, by writing or telephoning us at the following address or phone number:

Energy Future Holdings Corp.

1601 Bryan Street

Dallas, Texas 75201-3411

Attention: Investor Relations

Telephone: (214) 812-4600

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FORWARD-LOOKING STATEMENTS

This prospectus and other presentations made by us contain “forward-looking statements.” All statements, other than statements of historical facts, that are included in this prospectus, or made in presentations, in response to questions or otherwise, that address activities, events or developments that EFH Corp. expects or anticipates to occur in the future, including such matters as projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as “intends,” “plans,” “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “should,” “projection,” “target,” “goal,” “objective” and “outlook”), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors under “Risk Factors” contained elsewhere in this prospectus 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 Congress of the United States of America (“U.S.”) the U.S. Federal Energy Regulatory Commission (the “FERC”), the North American Electric Reliability Corporation (the “NERC”), the Texas Reliability Entity (the “TRE”), the PUCT, the Railroad Commission of Texas (the “RRC”), the U.S. Nuclear Regulatory Commission (the “NRC”), the U.S. Environmental Protection Agency (the “EPA”), the Texas Commission on Environmental Quality (the “TCEQ”) and the Commodity Futures Trading Commission (the “CFTC”), with respect to, among other things:

• allowed prices;

• allowed rates of return;

• permitted capital structure;

• industry, market and rate structure;

• purchased power and recovery of investments;

• operations of nuclear generating facilities;

• operations of fossil-fueled 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;

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

• clearing over the counter derivatives through exchanges and posting of cash collateral therewith;

• legal and administrative proceedings and settlements;

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• general industry trends;

• economic conditions, including the impact of a recessionary environment;

• our ability to attract and retain profitable customers;

• our ability to profitably serve our customers;

• restrictions on competitive retail pricing;

• changes in wholesale electricity prices or energy commodity prices;

• 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;

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

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

• access to adequate transmission facilities to meet changing demands;

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

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

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

• access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds in capital markets;

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

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

• competition for new energy development and other business opportunities;

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

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

• changes in electricity transmission that allow additional electricity generation to compete with our generation assets;

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

• changes in assumptions used to estimate costs of providing employee benefits, including pension benefits and other postretirement employee benefits (“OPEB”), and future funding requirements related thereto;

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• changes in assumptions used to estimate future executive compensation payments;

• hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards;

• significant changes in critical accounting policies;

• actions by credit rating agencies;

• our ability to effectively execute our operational strategy; and

• our ability to implement cost reduction initiatives.

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

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PROSPECTUS SUMMARY

This summary highlights selected information appearing elsewhere in this prospectus. This summary is not complete and does not contain all of the information that you should consider before participating in the exchange offer. You should carefully read this entire prospectus, including information set forth in the sections entitled “Risk Factors,” “Selected Historical Consolidated Financial Data for EFH Corp. and Its Subsidiaries” 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”).

“Legacy Notes” means, collectively, EFH Corp.’s 5.55% Series P Senior Notes due 2014, 6.50% Series Q Senior Notes due 2024 and 6.55% Series R Senior Notes due 2034. “EFH Corp. Senior Notes” means, collectively, EFH Corp.’s 10.875% Senior Notes due November 1, 2017 (EFH Corp. 10.875% Notes) and EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes). “EFH Corp. Senior Secured Notes” means EFH Corp.’s 9.75% Senior Secured Notes due October 15, 2019 (EFH Corp. 9.75% Notes). “EFIH Notes” means, collectively, Energy Future Intermediate Holding Company LLC’s (“EFIH”) and EFIH Finance Inc.’s (“EFIH Finance”) 9.75% Senior Secured Notes due October 15, 2019 (EFIH 9.75% Notes) and EFIH’s and EFIH Finance’s 10.000% Senior Secured Notes due December 1, 2020 (EFIH 10% Notes). The EFH Corp. Senior Secured Notes and the EFIH Notes are collectively referred to as the “Senior Secured Notes.” “TCEH Senior Notes” means, collectively, Texas Competitive Electric Holdings Company LLC’s (“TCEH”) and TCEH Finance Inc.’s (“TCEH Finance”) 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015, Series B (collectively, TCEH 10.25% Notes) and 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes). “TCEH Senior Secured Second Lien Notes” means, collectively, TCEH’s and TCEH Finance’s 15% Senior Secured Second Lien Notes due April 1, 2021 and 15% Senior Secured Second Lien Notes due April 1, 2021, Series B.

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.

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 used in this prospectus.

Our Businesses

We are a Dallas-based energy company with a portfolio of competitive and regulated energy businesses in Texas. EFH Corp. is a holding company conducting its operations principally through its subsidiaries, TCEH and Oncor Electric Delivery Company LLC (“Oncor”). TCEH is wholly-owned, and EFH Corp. holds an approximately 80% equity interest in Oncor.

TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Energy Future Competitive Holdings Company (“EFCH”) is the parent company of TCEH and a direct subsidiary of EFH Corp.

TCEH owns or leases 17,519 megawatts (“MW”) of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas-fueled generation facilities. This amount includes two new lignite-fueled units that achieved substantial completion (as defined in the engineering, procurement and construction agreements for the units) in the fourth quarter of 2009 but does not include a third new lignite-fueled unit that achieved substantial completion (as defined in the engineering, procurement and construction agreement for the unit) in the second quarter of 2010. In addition, TCEH is the largest purchaser of wind-generated electricity in Texas and the fifth largest in the United States. TCEH provides competitive electricity and related services to more than two million retail electricity customers in Texas.

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EFIH, a direct subsidiary of EFH Corp., is a holding company whose wholly-owned subsidiary, Oncor Electric Delivery Holdings Company LLC (“Oncor Holdings”), holds a majority interest (approximately 80%) in Oncor, which is principally engaged in providing electricity delivery services to retail electric providers, including subsidiaries of TCEH, that sell power in the north central, eastern and western parts of Texas.

Oncor is engaged in regulated electricity transmission and distribution operations in Texas that are primarily regulated by the PUCT. Oncor provides both distribution services to retail electric providers that sell electricity to consumers and transmission services to other electricity distribution companies, cooperatives and municipalities. Oncor operates the largest transmission and distribution system in Texas, delivering electricity to approximately three million homes and businesses and operating more than 117,000 miles of transmission and distribution lines. A significant portion of Oncor’s revenues represent fees for delivery services provided to TCEH. Distribution revenues from TCEH represented 38% and 39% of Oncor’s total revenues for the years ended December 31, 2009 and 2008, respectively.

EFH Corp. and Oncor have implemented certain structural and operational “ring-fencing” measures based on commitments made by Texas Holdings and Oncor to the PUCT that are intended to enhance the credit quality of Oncor. These measures serve to mitigate Oncor’s and Oncor Holdings’ credit exposure to Texas Holdings and its other subsidiaries (other than Oncor Holdings and its subsidiaries) (collectively, the “Texas Holdings Group”) and to reduce the risk that the assets and liabilities of Oncor or Oncor Holdings would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities. See Note 1 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for a description of the material features of these “ring-fencing” measures.

At September 30, 2010, we had approximately 9,200 full-time employees (including approximately 3,800 at Oncor), including approximately 2,750 employees (including approximately 660 at Oncor) under collective bargaining agreements.

Recent Developments

On November 15, 2010, TCEH and TCEH Finance (collectively, the “TCEH Issuer”), completed a private exchange transaction (the “Exchange Transaction”) pursuant to an Exchange Agreement among the TCEH Issuer, EFCH, the subsidiary guarantors named therein and an institutional investor (the “Exchange Holder”). In the Exchange Transaction, the TCEH Issuer issued approximately $885 million aggregate principal amount of its 15% Senior Secured Second Lien Notes due 2021, Series B in exchange for the surrender by certain funds and accounts managed by the Exchange Holder of approximately $1.27 billion aggregate principal amount of the TCEH Issuer’s 10.25% Senior Notes due 2015 and 10.50%/11.25% Senior Toggle Notes due 2016. The notes received by the TCEH Issuer in the Exchange Transaction have been retired and canceled.

On January 7, 2011, Oncor filed for a rate review with the PUCT and 203 cities. If approved as requested, this review would result in an aggregate annual rate increase of approximately $353 million. In its filing, Oncor also requested a revised regulatory capital structure of 55% debt to 45% equity. The debt-to-equity ratio established by the PUCT is currently set at 60% debt to 40% equity. The PUCT, cities and other participating parties, with input from Oncor, are expected to set a schedule for consideration of Oncor’s request. A resolution of Oncor’s proposed increase is expected to occur during the second half of 2011. Upon such resolution, any resulting rate changes will commence.

EFH Corp. was incorporated in Texas in 1996. EFIH was formed in Delaware in 2007. EFCH was incorporated in Texas in 1982. 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 website is http://www.energyfutureholdings.com. Information on or connected to our website does not constitute part of this prospectus.

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The Exchange Offer

The summary below describes the principal terms of the exchange offer. “The Exchange Offer” section of this Prospectus provides more comprehensive information. During the period from January 2010 through July 2010, EFH Corp. issued the outstanding notes in private placements. The term “notes” as used throughout this prospectus collectively refers to the outstanding notes and the exchange notes.

General In connection with the private placements, EFH Corp. and the guarantors of the outstanding notes entered into a registration rights agreement with the initial purchasers and other purchasers of the outstanding notes pursuant to which they agreed, among other things, to deliver this prospectus to you and to complete the exchange offer within 360 days after the date of original issuance of the outstanding notes. You are entitled to exchange in the exchange offer your outstanding notes for 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 that 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 Offer EFH Corp. is offering to exchange $1,060,757,000 aggregate principal amount of 10.000% Senior Secured Notes due 2020 that have been registered under the Securities Act for any and all of its existing 10.000% Senior Secured Notes due 2020.

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 offer 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

• 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.”

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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 offer 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 offer will expire at 11:59 p.m., New York City time, on March 1, 2011, 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 offer. 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 offer.

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

Accrued Interest on the Exchange Notes and the Outstanding Notes The exchange notes will accrue interest from the most recent date to which interest has been paid on the outstanding notes. Holders of outstanding notes that are accepted for exchange will be deemed to have waived the right to receive any further interest payments with respect to such outstanding notes.

Procedures for Tendering Outstanding Notes To participate in the exchange offer, you must follow procedures established by The Depository Trust Company, or “DTC,” for tendering notes held in book-entry form. These procedures require that:

• the exchange agent receive, prior to the expiration date of the exchange offer, a computer generated message known as an “agent’s message,” which message is transmitted through DTC’s automated tender offer program known as “ATOP;” and

• DTC confirm (i) that it has received your instructions to exchange your notes and (ii) that you agree to be bound by the terms of the letter of transmittal.

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For more information on tendering your outstanding notes, please refer to the sections in this prospectus entitled “The Exchange Offer — Terms of the Exchange Offer” and “— Procedures for Tendering Outstanding Notes.”

No Guaranteed Delivery The exchange offer will not provide for guaranteed delivery procedures with respect to any outstanding notes.

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 offer, 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 following completion of the exchange offer. If you do not tender your outstanding notes in the exchange offer, 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 offer, 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 offer, EFH Corp. and the guarantors of the notes do not currently anticipate that they will register the outstanding notes under the Securities Act.

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

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

Exchange Agent The Bank of New York Mellon Trust Company, N.A. is the exchange agent for the exchange offer. The addresses and telephone numbers of the exchange agent are set forth in the section captioned “The Exchange Offer — 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 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 Energy Future Holdings Corp.

Securities Offered $1,060,757,000 aggregate principal amount of 10.000% Senior Secured Notes due 2020.

Maturity Date January 15, 2020.

Interest Rate The exchange notes will accrue interest at the rate of 10.000% per annum.

Interest Payment Dates Interest on the notes will be payable on January 15 and July 15 of each year.

Ranking The exchange notes will be:

• senior obligations of EFH Corp. and will rank equally in right of payment with all existing and future senior indebtedness of EFH Corp. (including the Legacy Notes, the EFH Corp. Senior Notes and the EFH Corp. Senior Secured Notes);

• effectively subordinated to any indebtedness of EFH Corp. secured by assets of EFH Corp. to the extent of the value of the assets securing such indebtedness;

• structurally subordinated to all indebtedness and other liabilities of EFH Corp.’s non-guarantor subsidiaries, including Oncor Holdings, TCEH and each of their respective subsidiaries, any of EFH Corp.’s foreign subsidiaries and any other unrestricted subsidiaries;

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

• guaranteed as described under “— Guarantees.”

As of September 30, 2010, (1) EFH Corp. had $1.176 billion principal amount of senior secured indebtedness, including the notes, and (2) the outstanding notes were structurally subordinated to approximately $35.909 billion principal amount of debt (including long-term debt, including amounts due currently, and short-term borrowings) of EFH Corp.’s subsidiaries, including all of TCEH’s and its subsidiaries’ debt and all of Oncor Holdings’ and its subsidiaries’ debt. As of September 30, 2010, TCEH had approximately $3.03 billion of additional available capacity under the TCEH Senior Secured Facilities (excluding amounts available under its senior secured cash posting credit facility, but including $229 million of undrawn commitments from a subsidiary of Lehman Brothers Holding Inc. (such subsidiary, “Lehman”) that has filed for bankruptcy under Chapter 11 of Title 11 of the United States Code, as amended (the “Bankruptcy Code”) that are only available from the fronting banks and the swingline lender and $410 million of available letter of credit capacity), and Oncor had approximately $1.444 billion of additional available capacity under its revolving credit facility (excluding $122 million of undrawn commitments from Lehman and subject to certain bond credit availability). In addition, the TCEH Senior Secured Facilities permit TCEH to issue up to $5.0 billion of secured notes or loans ranking junior to TCEH’s senior secured borrowings.

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Guarantees The notes are unconditionally guaranteed, jointly and severally, by EFCH (the parent of TCEH) on a senior unsecured basis and EFIH (the parent of Oncor Holdings) on a senior secured basis (to the extent of the assets securing the guarantee).

The guarantees:

• are senior obligations of each guarantor and rank equally in right of payment with all existing and future senior indebtedness of each guarantor;

• in the case of the guarantee from EFIH, are secured, equally and ratably with EFIH’s guarantee of the EFH Corp. Senior Secured Notes and the EFIH Notes, by the pledge of any investments EFIH owns or holds in Oncor Holdings or any of its subsidiaries (the “Collateral”), which consists of all of the membership interests it owns in Oncor Holdings;

• in the case of the guarantee from EFCH, are not secured;

• in the case of the guarantee from EFIH, are effectively senior to all unsecured indebtedness of EFIH to the extent of the value of the Collateral securing such guarantee;

• are effectively subordinated to all secured indebtedness of each guarantor secured by assets other than the Collateral to the extent of the value of the assets securing such indebtedness;

• are structurally subordinated to any existing and future indebtedness and liabilities of subsidiaries of a guarantor that do not guarantee the notes, including Oncor Holdings and its subsidiaries (collectively, the “Oncor Subsidiaries” and each, an “Oncor Subsidiary”) in the case of EFIH, and TCEH and its subsidiaries in the case of EFCH, and any other unrestricted subsidiaries;

• are senior in right of payment to any future subordinated indebtedness of each guarantor; and

• are effectively senior, in the case of EFIH, to all obligations under any future junior lien debt with respect to the Collateral.

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As of September 30, 2010, the EFCH guarantee was effectively junior to approximately $98 million principal amount of senior secured indebtedness of EFCH (excluding EFCH’s secured guarantee of $21.330 billion of senior secured borrowings by TCEH under the TCEH Senior Secured Facilities). As of September 30, 2010, TCEH had approximately $3.03 billion of additional available senior secured capacity under the TCEH Senior Secured Facilities (excluding amounts available under its senior secured cash posting credit facility, but including $229 million of undrawn commitments from Lehman that are only available from the fronting banks and the swingline lender and $410 million of available letter of credit capacity). In addition, the TCEH Senior Secured Facilities permit TCEH to issue up to $5.0 billion of notes or loans ranking junior to TCEH’s senior secured borrowings.

None of EFH Corp.’s other subsidiaries guarantee the notes. For the year ended December 31, 2009 and the nine months ended September 30, 2010, the non-guarantor subsidiaries generated all of EFH Corp.’s consolidated total revenue. In addition, as of September 30, 2010, TCEH held approximately 83% of EFH Corp.’s consolidated total assets and the remaining assets primarily reflected EFH Corp.’s investment in Oncor Holdings.

See “Risk Factors — Risks Related to the Notes — The liabilities of each of EFH Corp. and EFCH currently exceed its assets as shown on its most recent quarterly balance sheet. If a court were to find that EFH Corp., EFCH or EFIH were insolvent before or after giving effect to the offering of the notes and did not receive reasonably equivalent value or fair consideration for the issuance of the notes or the incurrence of a guarantee or the pledge of the Collateral, as applicable, the court may void all or a portion of the obligations represented by the notes or the guarantee of the notes by EFCH or EFIH or the pledge of the Collateral by EFIH as a fraudulent conveyance.”

Security EFIH’s guarantee of the notes is secured, equally and ratably with EFIH’s guarantee of the EFH Corp. Senior Secured Notes and the EFIH Notes, by its pledge of 100% of the membership interests and other investments it owns or holds in Oncor Holdings. As of the date of this prospectus, $115 million of EFH Corp. Senior Secured Notes and $2.321 billion of EFIH Notes were outstanding. See “Description of the Notes — Security for the Notes.” See also “Risk Factors — Risks Related to the Notes — The liabilities of each of EFH Corp. and EFCH currently exceed its assets as shown on its most recent quarterly balance sheet. If a court were to find that EFH Corp., EFCH or EFIH were insolvent before or after giving effect to the offering of the notes and did not receive reasonably equivalent value or fair consideration for the issuance of the notes or the incurrence of a guarantee or the pledge of the Collateral, as applicable, the court may void all or a portion of the obligations represented by the notes or the guarantee of the notes by EFCH or EFIH or the pledge of the Collateral by EFIH as a fraudulent conveyance.”

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Optional Redemption EFH Corp. may redeem any of the exchange notes on and after January 15, 2015 at the redemption prices set forth in this prospectus. EFH Corp. may also redeem the exchange notes at any time prior to January 15, 2015 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. In addition, before January 15, 2013, 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.”

Change of Control Offer Upon the occurrence of certain transactions meeting the definition of “change of control,” holders of the exchange notes will have the right to require EFH Corp. to repurchase some or all of the exchange notes at 101% of their face amount, plus accrued and unpaid interest to the repurchase date. This right is subject to important limitations. For example, this right will not apply to a transaction that would otherwise be a “change of control” if EFH Corp. complies with the provisions relating to a transfer of either the Oncor business or the TCEH business described below under “— Important Covenants” or if the transaction meets certain other requirements. See “Description of the Notes — Repurchase at the Option of Holders — Change of Control” and the definition of “Change of Control” under “Description of the Notes.”

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 the TCEH Senior Secured Facilities, may prevent EFH Corp. from making such payment or receiving funds from its subsidiaries in an amount sufficient to fund such payment.

See “Risk Factors — Risks Related to the Notes — We may not be able to repurchase the notes upon a change of control,” “Risk Factors — Risks Related to the Notes — We may transfer or dispose of our interests in EFIH or Oncor Holdings to a third party in a manner that would result in EFIH or such third party becoming the obligor under the notes, without EFH Corp. or EFIH being required to offer to repurchase the notes. The risks of an investment in the notes may increase further following such a transaction” and “Risk Factors — Risks Related to the Notes — We may transfer or dispose of our interests in or the assets of TCEH to a third party without such third party becoming the obligor under the notes and without being required to offer to repurchase the notes.”

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:

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

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• make investments (including investments in Oncor);

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

• create liens on assets to secure debt;

• sell assets;

• consolidate, merge, sell or otherwise dispose of all or substantially all of their assets in certain circumstances;

• enter into certain transactions with their affiliates; and

• designate EFH Corp.’s subsidiaries as unrestricted subsidiaries.

These covenants are subject to a number of important limitations and exceptions. For example, the first to occur of the sale of all of the Oncor business (as defined under “Permitted Asset Transfer” under “Description of the Notes”) and all of the TCEH business (as defined under “TCEH Transfer” under “Description of the Notes”) will not be considered the sale of all or substantially all of EFH Corp.’s assets under the indenture so long as certain conditions are satisfied, in the case of the sale of the Oncor business, including the condition that the transferee assumes the obligations under the exchange notes. The transferee in the case of a TCEH Transfer would not be required to assume such obligations. Certain other transactions (including certain intercompany transactions) involving the Oncor business will also not be considered the sale of all or substantially all of EFH Corp.’s assets. Additionally, up to an aggregate of $4.0 billion of indebtedness secured by a first priority lien on the Collateral, including the Senior Secured Notes and the exchange notes, may be incurred under the indenture.

Oncor Holdings, the immediate parent of Oncor, and its subsidiaries and Comanche Peak Nuclear Power Company LLC, Nuclear Energy Future Holdings LLC and Nuclear Energy Future Holdings II LLC are unrestricted subsidiaries under the indenture and, accordingly, are not subject to any of the restrictive covenants in the indenture. See “Description of the Notes.”

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.

Listing EFH Corp. does not intend to list the exchange notes for trading on any securities exchange or automated quotation system.

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Risk Factors In addition to the other information included in this prospectus, you should carefully consider the information set forth in the section entitled “Risk Factors” beginning on page 15 before deciding whether or not to participate in the exchange offer.

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EFH Corp. and its Subsidiaries

Summary Historical Consolidated Financial Data

The following table sets forth our summary historical consolidated financial data as of and for the periods indicated. The historical financial data as of December 31, 2009 and 2008 (Successor) and for the years ended December 31, 2009 and 2008 (Successor), the period from October 11, 2007 through December 31, 2007 (Successor) and the period from January 1, 2007 through October 10, 2007 (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, 2007 (Successor), 2006 (Predecessor) and 2005 (Predecessor) and for the years ended December 31, 2006 and 2005 (Predecessor) have been derived from our audited historical consolidated financial statements that are not included in this prospectus. The “Predecessor” period reflects the period prior to the Merger, which occurred on October 10, 2007. The historical financial data as of September 30, 2010 and for the nine months ended September 30, 2010 and 2009 have been derived from our unaudited historical interim condensed consolidated financial statements and related notes included elsewhere in this prospectus. In EFH Corp.’s opinion, such unaudited interim financial data reflects all adjustments, consisting of normal recurring accruals, 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 historical consolidated financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Year Ended December 31, 2009” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010,” and our historical consolidated financial statements and related notes that are included elsewhere in this prospectus.

	Successor									Predecessor
	Year Ended December 31,						Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007		Year Ended December 31,
	2009			2008								2006		2005
	(millions of dollars, except ratios and per share amounts)
Statement of Income Data:
Operating revenues	$	9,546		$	11,364		$	1,994		$	8,044	$	10,703	$	10,826
Income (loss) from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles		408			(9,998	)		(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	)
Preference stock dividends		—			—			—			—		—		10
Net income (loss)		408			(9,998	)		(1,360	)		723		2,552		1,712
Net income (loss) attributable to noncontrolling interests		(64	)		160			—			—		—		—
Net income (loss) attributable to EFH Corp.		344			(9,838	)		(1,360	)		723		2,552		1,712
Dividends declared per share	$	—		$	—		$	—		$	1.30	$	1.67	$	1.26
Ratio of earnings to fixed charges (a)		1.24			—			—			2.30		5.11		3.80
Ratio of earnings to combined fixed charges and preference dividends (a)		1.24			—			—			2.30		5.11		3.74

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	Successor									Predecessor
	Year Ended December 31,						Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31,
	2009			2008									2006			2005
	(millions of dollars, except ratios and per share amounts)
Statement of Cash Flows Data:
Cash flows provided by (used in) operating activities from continuing operations	$	1,711		$	1,505		$	(450	)	$	2,265		$	4,954		$	2,793
Cash flows provided by (used in) financing activities from continuing operations		422			2,837			33,865			1,394			(2,332	)		(1,563	)
Cash flows used in investing activities from continuing operations		(2,633	)		(2,934	)		(34,563	)		(2,283	)		(2,664	)		(1,038	)
Other Financial Data:
Capital expenditures, including nuclear fuel	$	2,545		$	3,015		$	716		$	2,542		$	2,337		$	1,148

	Successor								Predecessor
	December 31,								December 31,
	2009			2008			2007		2006		2005
	(millions of dollars)
Balance Sheet Data:
Total assets	$	59,662		$	59,263		$	64,804	$	27,216	$	27,978
Property, plant & equipment — net		30,108			29,522			28,650		18,569		17,006
Goodwill and intangible assets		17,192			17,379			27,319		729		728
Total debt (b)		43,426			42,460			40,834		12,607		13,380
Preferred stock of subsidiaries (c)		—			—			—		—		—
Total equity		(1,836	)		(2,318	)		6,685		2,140		475

(a) Fixed charges exceeded “earnings” (net loss) by $10.469 billion and $2.034 billion for the year ended December 31, 2008 and for the period from October 11, 2007 through December 31, 2007, respectively.

(b) Includes long-term debt, including amounts due currently, and short-term borrowings. Also includes equity-linked debt securities in the amount of $179 million for the year ended December 31, 2005.

(c) Preferred stock outstanding at the end of 2008, 2007, 2006 and 2005 has a stated amount of $51 thousand. There was no outstanding preferred stock at the end of 2009.

Although EFH Corp. continued as the same legal entity after the Merger in October 2007, its “Summary Historical Consolidated Financial Data” for periods preceding the Merger and for periods succeeding the Merger are presented as the consolidated financial statements of the “Predecessor” and the “Successor,” respectively. See “Basis of Presentation” in Note 1 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 included elsewhere in this prospectus. The consolidated financial statements of the Successor also reflect the application of “purchase accounting.” Results for 2008 were significantly impacted by impairment charges related to goodwill, trade name and emission allowances intangible assets and natural gas-fueled generation plants. Results for 2010 reflect the prospective adoption of amended guidance regarding consolidation accounting standards related to variable interest entities that resulted in the deconsolidation of Oncor Holdings as discussed in Note 3 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 included elsewhere in this prospectus and amended guidance regarding transfers of financial assets that resulted in the accounts receivable securitization program no longer being accounted for as a sale of accounts receivable and the funding under the program now reported as short-term borrowings as discussed in Note 5 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 included elsewhere in this prospectus. Results for 2010 were significantly impacted by a goodwill impairment charge as discussed in Note 4 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010.

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	Successor
	Nine Months Ended September 30, 2010			Nine Months Ended September 30, 2009
	(millions of dollars, except ratios)
Statement of Income Data:
Operating revenues	$	6,599		$	7,366
Net income (loss)		(2,973	)		261
Net income attributable to noncontrolling interests		—			(54	)
Net income (loss) attributable to EFH Corp		(2,973	)		207
Ratio of earnings to fixed charges (b)		—			1.21
Ratio of earnings to combined fixed charges and preference dividends		—			1.21
Statement of Cash Flows Data:
Cash flows provided by operating activities	$	966		$	1,743
Cash flows provided by (used in) financing activities		(1,167	)		420
Cash flows used in investment activities		(307	)		(2,127	)
Other Financial Data:
Capital expenditures, including nuclear fuel	$	793		$	2,034
	Successor
	September 30, 2010
	(millions of dollars)
Balance Sheet Data:
Total assets	$	47,114
Property, plant & equipment — net		20,530
Goodwill and intangible assets		8,618
Total debt (a)		35,729
Total equity		(6,068	)

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

(b) Fixed charges exceeded earnings by $2.736 billion million for the nine months ended September 30, 2010.

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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 participate in the exchange offer. The selected risks described below 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. Any of the following risks could materially and adversely affect our business, financial condition, operating results or cash flow. 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 noteholders may lose all or part of their original investment.

Risks Related to the Exchange Offer

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 offer, you will continue to be subject to restrictions on transfer of your 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 Offer” and “The Exchange Offer” for information about how to tender your outstanding notes.

The tender of outstanding notes under the exchange offer 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 there is no assurance that any active trading market will develop for the exchange notes.

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 offer or the effectiveness of a shelf registration statement in lieu thereof. Therefore, we cannot assure you that an active market for the exchange notes will develop or, if developed, that it will 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.

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

Based on interpretations of the staff of the SEC contained inExxon Capital Holdings Corp., SEC no-action letter (May 13, 1988),Morgan Stanley & Co. Inc., SEC no-action letter (June 5, 1991) andShearman & Sterling, SEC no-action letter (July 2, 1993), 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.

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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 indentures governing the notes, the Senior Secured Notes, the EFH Corp. Senior Notes, the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities, 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 default on obligations to pay indebtedness, we may not be able to make payments on the notes.

Any default under our or our subsidiaries’ 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, which could substantially decrease the market price 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 indebtedness, or if we or our subsidiaries otherwise fail to comply with the various covenants, including any financial and operating covenants, in the instruments governing our or 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 or the TCEH Senior Secured Second Lien Notes, 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 and seek a waiver, they may not be able to obtain a waiver from the 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, liquidation or insolvency.

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, EFH Corp. will be required to offer to repurchase all of the notes at 101% of their principal amount plus accrued and unpaid interest. The source of funds for any purchase of the notes will be EFH Corp.’s available cash or cash generated from its subsidiaries’ operations or other sources, including borrowings, sales of assets or sales of equity. EFH Corp. may not be able to repurchase the notes upon a change of control because it may not have sufficient financial resources to purchase all of the notes that are tendered upon a change of control. Further, EFH Corp. may be restricted under the terms of debt agreements of TCEH, EFIH and Oncor from receiving funds from TCEH and Oncor sufficient to repurchase all of the notes tendered by holders upon a change of control. Accordingly, EFH Corp. may not be able to satisfy its obligations to purchase the notes unless it is able to refinance or obtain waivers under the instruments governing its indebtedness. EFH Corp.’s failure to repurchase the notes upon a change of control would cause a default under the indenture governing the notes and a cross-default under certain of EFH Corp.’s 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.

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EFCH’s guarantee of the notes is effectively subordinated to those lenders who have a security interest in its assets.

EFCH’s 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 EFCH 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 is not secured by any of EFCH’s assets, 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.

The notes are secured only to the extent of the value of the assets that have been granted as security for EFIH’s guarantee of the notes.

The Collateral securing EFIH’s guarantee of the notes includes only EFIH’s membership interests and other investments that EFIH owns or holds in Oncor Holdings and its subsidiaries (which consists of 100% of the membership interests of Oncor Holdings, which are owned by EFIH), but does not include any assets of Oncor Holdings or its subsidiaries. Oncor Holdings owns approximately 80% of Oncor. No appraisals of any of the Collateral securing the guarantee by EFIH of the notes have been prepared by or on behalf of EFH Corp. The fair market value of the Collateral may not be sufficient to repay the holders of the notes upon any foreclosure. The fair market value of the membership interests of Oncor Holdings is subject to fluctuations based on factors that include, among other things, the financial results and prospects of Oncor Holdings and its subsidiaries and its ability to implement its business strategy, Oncor’s capital structure and the amount of its other existing indebtedness (as to which EFH Corp. will have no control), applicable regulatory approvals that may be required to foreclose on the membership interests of Oncor Holdings and subsequently dispose of the membership interests of Oncor Holdings, the ability to sell the membership interests of Oncor Holdings in an orderly sale, general economic conditions, the availability of buyers and similar factors. Furthermore, upon a foreclosure in the Collateral, holders may be limited in their ability to obtain the best price for the Collateral if they are unable to exercise a “drag-along” right to force Texas Transmission Investment LLC (“Texas Transmission”), Oncor’s primary minority owner, to sell its membership interests pursuant to the terms of the investor rights agreement, dated November 5, 2007, among EFH Corp., Oncor Holdings, Oncor and Texas Transmission (the “Investor Rights Agreement”). In addition, a court could limit recoverability if it were to apply non-New York law to a proceeding and deem a portion of the interest claim usurious in violation of public policy. The amount to be received upon a sale of any Collateral would be dependent on numerous factors, including but not limited to the actual fair market value of the Collateral at such time, general, market and economic conditions and the timing and the manner of the sale.

EFIH’s guarantees of the EFH Corp. Senior Secured Notes and the EFIH Notes are also secured by the Collateral, equally and ratably with the notes.

In the event that a bankruptcy or similar proceeding is commenced by or against EFH Corp., if at the time of the filing the value of the membership interests of Oncor Holdings and other Collateral is less than the amount of principal and accrued and unpaid interest on the notes and the Senior Secured Notes, interest may cease to accrue on the notes thereafter. If at the time of the filing the value of the membership interests of Oncor Holdings and other Collateral is greater than the amount of principal and accrued and unpaid interest on the notes and the Senior Secured Notes, interest may nevertheless cease to accrue at a subsequent time if at such time the value ceases to be in excess of the principal and accrued and unpaid interest. It is possible, given the broad discretionary powers of a bankruptcy court, even if at the time of the filing the value of the membership interests of Oncor Holdings and other Collateral is greater than the amount of principal and accrued and unpaid interest on the notes and the Senior Secured Notes on the date of filing, claims on the membership interests of Oncor Holdings and other Collateral for interest accruing from and after the date the bankruptcy petition is filed might not be allowed. In the event of a foreclosure, liquidation, bankruptcy or similar proceeding, the proceeds from any sale of the membership interests of Oncor Holdings and other Collateral may not be sufficient to pay the obligations due under the notes.

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To the extent that the claims of the holders of the notes and the Senior Secured Notes exceed the value of the membership interests of Oncor Holdings and other Collateral, those claims will rank equally with the claims of the holders of EFH Corp.’s then outstanding senior notes and other senior debt. As a result, if the value of the membership interests of Oncor Holdings and other Collateral is less than the value of the claims of the holders of the notes and the Senior Secured Notes, those claims may not be satisfied in full.

The security interest granted in favor of the collateral trustee is subject to practical problems generally associated with the realization of security interests in collateral. For example, the collateral trustee may need to obtain the consent of a third party to obtain or enforce a security interest in a contract, and we cannot assure you that the collateral trustee will be able to obtain any such consent. The consents of any third parties may not be given when required to facilitate a foreclosure on any particular assets. Accordingly, the collateral trustee may not have the ability to foreclose upon such assets, and the value of the Collateral may significantly decrease.

Regulatory approvals may be required in order to enforce the security interests in the Collateral and to dispose of an interest in, or operational control of, the Collateral that secures EFIH’s guarantee of the notes.

The Collateral securing EFIH’s guarantee of the notes includes all of EFIH’s membership interests and other investments that EFIH owns or holds in Oncor Holdings and its subsidiaries. Pursuant to the Public Utility Regulatory Act (“PURA”), Texas Utilities Code §§39.262(l) and 39.915, an electric utility must obtain prior PUCT approval of any change in majority ownership, controlling ownership or operational control of Oncor. As a result, prior to any foreclosure on the membership interests of Oncor Holdings, approval of the PUCT may be required for a change in ownership or control of Oncor Holdings. Pursuant to PURA §§39.262(m) and 39.915(b), the PUCT will approve such a transfer if it finds that the transaction is in the public interest. In making its determination, these sections of PURA provide that the PUCT will consider whether the transaction will adversely affect the reliability of service, availability of service or cost of service of Oncor. Therefore, in connection with any action taken to enforce the security against the Collateral, such approval may not be granted and, if it were to be granted, it is not known how long it would take to obtain such approval. Even if the approval were granted to foreclose on the Collateral, then additional prior PUCT approval may also be required for any subsequent change in majority ownership, controlling ownership or operational control in the membership interests of Oncor Holdings. Additionally, Texas Holdings has committed to hold a majority ownership interest in Oncor through October 10, 2012. This commitment is incorporated in the Order on Rehearing in PUCT Docket No. 34077.

In addition, pursuant to the terms of the Investor Rights Agreement, any transfer of the equity interests in Oncor Holdings to a third party, including as a result of any enforcement of the lien on the Collateral securing EFIH’s guarantee of the notes, EFIH’s guarantee of the EFH Corp. Senior Secured Notes and the EFIH Notes, may be limited and give rise to a tag-along right of Texas Transmission, the primary minority investor in Oncor, to participate in that transfer on a pro rata basis, which may hinder the enforcement of the lien on the Collateral in a timely manner, if at all.

In the event of EFH Corp.’s bankruptcy, the ability of the holders of the notes to realize upon the Collateral securing EFIH’s guarantee of the notes will be subject to certain bankruptcy law limitations.

The right of the trustee for the notes to repossess and dispose of the Collateral, which secures EFIH’s guarantee of the notes, upon acceleration is likely to be significantly impaired by federal bankruptcy law if bankruptcy proceedings are commenced by or against EFH Corp. This could be true even if bankruptcy proceedings are commenced after the trustee for the notes has repossessed and disposed of the Collateral. Under bankruptcy law, a secured creditor, such as the trustee for the notes, is prohibited from repossessing collateral from a debtor in a bankruptcy case, or from disposing of collateral repossessed from a debtor, without bankruptcy court approval. Moreover, bankruptcy law permits the debtor to continue to retain and to use any such collateral, and the proceeds, products, rents or profits of such collateral, even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.” The meaning of the term “adequate protection” varies according to circumstances, but in general the doctrine of “adequate protection” requires a debtor to protect the value of a secured creditor’s interest in the collateral, through cash payments, the granting of an additional security interest or otherwise. It is impossible to predict whether or when payments in respect of the notes might be made following commencement of a bankruptcy case, whether or when the trustee would repossess or dispose of the Collateral, or whether or to what extent holders of the notes would be compensated for any delay in payment or loss of value of the Collateral through the requirements of “adequate protection.” Furthermore, in the event the bankruptcy court determines that the value of the Collateral is not sufficient to repay all amounts due on the notes, the holders of the notes would have unsecured “deficiency claims” as to the difference. Federal bankruptcy laws do not generally permit the payment of interest, costs, or attorneys’ fees for unsecured claims during the debtor’s bankruptcy case.

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The indenture governing the notes does not limit or restrict the activities of Oncor Holdings and its subsidiaries.

Oncor Holdings and its subsidiaries are not “Restricted Subsidiaries” under the indenture governing the notes (except under certain circumstances, such as in connection with the calculation of the “fixed charge coverage ratio” or “consolidated leverage ratio” for purposes of making certain restricted payments; see “Description of the Notes”). As of the date of this prospectus, EFIH’s subsidiaries (other than EFIH Finance, the co-issuer of the EFIH Notes) consist only of Oncor Holdings and its subsidiaries, all of which are unrestricted subsidiaries of EFH Corp. Accordingly, none of EFIH’s subsidiaries (other than EFIH Finance) are subject to the restrictive covenants contained in the notes, described under “Description of the Notes,” and none of EFIH’s subsidiaries guarantee the notes.

Because Oncor Holdings and its subsidiaries are unrestricted subsidiaries of EFH Corp. under the indenture governing the notes and are therefore not subject to any of the restrictive covenants therein, the indenture does not serve to limit or restrict the ability of Oncor Holdings or its subsidiaries to take any actions or enter into any transactions that would impair their ability to dividend funds to EFH Corp. to make payments on the notes and other debt of EFH Corp., or that would negatively affect the value of EFIH’s equity interests in Oncor Holdings that are pledged as Collateral for the notes, such as incurring debt, selling or transferring all or a portion of the assets of Oncor Holdings or its subsidiaries, entering into joint ventures, dividending out assets or engaging in speculative investments. Certain actions that would negatively affect the value of the Collateral may increase the ability of EFH Corp. to make restricted payments.

Under the indenture governing the notes, holders of the notes agree not to file a bankruptcy proceeding against Oncor Holdings or any of its subsidiaries.

Holders that receive the notes acknowledge and agree that they will 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, Oncor or any of their subsidiaries, or against any of the assets of Oncor Holdings, Oncor or any of their subsidiaries. Such holders further acknowledge and agree that each of Oncor Holdings, Oncor and any of their subsidiaries is a third party beneficiary of the foregoing covenant and have the right to specifically enforce such covenant in any proceeding at law or in equity.

The value of the Collateral may be diluted if we issue additional debt that is secured equally and ratably by the same Collateral securing the guarantee by EFIH of the notes or if the Collateral is sold.

The Senior Secured Notes are secured by the Collateral on a parity lien basis with the notes. In addition, the indentures governing the Senior Secured Notes provide, and the indenture governing the notes provides, that EFH Corp. and EFIH may incur up to an aggregate of $4.0 billion of debt, including the Senior Secured Notes and the notes, which would be secured on a parity lien basis by the Collateral. Therefore, because the principal amount of the Senior Secured Notes and the notes are, in the aggregate, less than $4.0 billion, EFH Corp. and EFIH may subsequently incur additional debt secured on a parity lien basis by the Collateral up to the $4.0 billion limit, subject to restrictions on their ability to incur debt and liens under the indenture governing the notes and under other documents governing their indebtedness. To the extent that any of this additional debt is incurred in the future, the interests of holders of the notes in the Collateral will be diluted. Additionally, EFH Corp. and EFIH are not restricted from issuing additional debt that is secured by a junior lien on the Collateral, subject to restrictions on their ability to incur debt and liens under the indenture governing the notes and under other documents governing their indebtedness.

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The collateral trust agreement governing the pledge of Collateral generally provides that the holders of a majority of the debt secured by a first priority lien on the Collateral, including the Senior Secured Notes, the notes and other future debt incurred by EFH Corp. or EFIH secured by the Collateral equally and ratably, have, subject to certain limited exceptions, the exclusive right to manage, perform and enforce the terms of the security documents securing the rights of secured debtholders in the Collateral, and to exercise and enforce all privileges, rights and remedies thereunder. To the extent that EFH Corp. and/or EFIH incurs additional secured debt that is secured equally and ratably with the notes and the amount of this secured debt, alone or together with any Senior Secured Notes, exceeds the amount of the notes, the holders of such secured debt may be able to exercise control under the collateral trust agreement and other security documents.

EFIH in most cases has control over the Collateral securing its guarantee of the notes, and to the extent permitted, its sale by EFIH would eliminate the collateral securing such guarantee. The documents governing the pledge of the Collateral permit EFIH to remain in possession of, retain exclusive control over, freely operate and collect, invest and dispose of, any income from, the Collateral, such as cash dividends. In addition, in certain limited circumstances EFIH has the right to sell the Collateral free and clear of the security interest underlying the notes.

Rights of holders of the notes in the Collateral may be adversely affected by the failure to perfect security interests in certain Collateral acquired in the future.

EFIH may acquire assets or investments in the future that would be required to be pledged as Collateral securing the notes. There can be no assurance that the trustee or the collateral trustee will monitor, or that we will inform the trustee or the collateral trustee of, the future acquisition of assets or investments that would be required to be pledged as Collateral, and that the necessary action will be taken to properly perfect the security interest in such after-acquired Collateral. Neither the trustee nor the collateral trustee has an obligation to monitor the acquisition of additional assets or investments that are required to be pledged as Collateral or the perfection of any security interest in such Collateral. Such failure may result in the loss of the security interest in the Collateral or the priority of the security interest in favor of the notes against third parties.

We may transfer or dispose of our interests in EFIH or Oncor Holdings to a third party in a manner that would result in EFIH or such third party becoming the obligor under the notes, without EFH Corp. or EFIH being required to offer to repurchase the notes. The risks of an investment in the notes may increase further following such a transaction.

The indenture governing the notes provides that EFH Corp. may engage in a “Permitted Asset Transfer” with respect to EFH Corp.’s ownership of EFIH or EFIH’s ownership of Oncor Holdings that would result in the obligations under the notes being assumed by EFIH or by a third party to which the investments in Oncor Holdings and its subsidiaries are transferred in any such Permitted Asset Transfer (referred to as a “third party transferee”). The indenture governing the EFH Corp. Senior Secured Notes contains similar provisions. This prospectus does not include or incorporate by reference financial statements or other financial data of EFIH. However, this prospectus includes financial statements of Oncor Holdings. See Oncor Holdings’ audited historical consolidated financial statements for the year ended December 31, 2009 and unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2010, each of which is included elsewhere in this prospectus. A Permitted Asset Transfer includes:

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• the direct or indirect sale, assignment, transfer, conveyance or other disposition (including by way of merger, wind-up or consolidation) or spin-off of the equity of EFIH such that it is no longer a subsidiary of EFH Corp., and

• the sale, assignment, transfer, conveyance or other disposition (other than by way of merger, wind-up or consolidation) of all of EFIH’s equity interests and other investments in the Oncor Subsidiaries or successor Oncor business and all other Collateral held by EFIH.

If a valid Permitted Asset Transfer occurs, the notes would become obligations of EFIH or the third party transferee of the investments in the Oncor Subsidiaries, which would result in the guarantee of EFCH being released and EFH Corp. no longer being liable on the notes and the EFH Corp. Senior Secured Notes unless EFH Corp. is the transferee. Currently, and for some period of time after the date of this prospectus, it is expected that EFH Corp. will rely on the cash flows from TCEH and its subsidiaries to service its debt obligations, including the notes and the Senior Secured Notes. Following the completion of a Permitted Asset Transfer, other than a merger of EFIH into EFH Corp., the cash flows from EFH Corp. and its other subsidiaries, including TCEH and its subsidiaries, would no longer be available to pay interest and principal on the notes and the EFH Corp. Senior Secured Notes that would have become EFIH’s obligation in connection with the Permitted Asset Transfer, and holders of the transferred notes would not be able to look to the assets of EFH Corp. and TCEH and its subsidiaries in the case of a bankruptcy, liquidation or insolvency with respect to EFIH. As of September 30, 2010, the assets of EFIH and its subsidiaries (including EFIH’s investment in the Oncor Subsidiaries) represented approximately 12% of the total consolidated assets of EFH Corp. and its subsidiaries. In connection with a Permitted Asset Transfer to a third party transferee, such third party transferee would not be a subsidiary of EFH Corp. and would not have the access to such cash flows to service its debt obligations, which would include the transferred notes and the transferred Senior Secured Notes, nor would such third party transferee be able to look to the assets of EFH Corp. and its subsidiaries in the case of a bankruptcy, liquidation or insolvency. In addition, such third party transferee, as the successor obligor, may not have sufficient sources of capital to service its debt and the obligations under the notes and the Senior Secured Notes, and distributions from the Oncor Subsidiaries may not be available or sufficient to service the obligations under such notes. No Oncor Subsidiary will become obligated on the notes and the Senior Secured Notes as a result of a Permitted Asset Transfer.

Additionally, if a Permitted Asset Transfer occurs in accordance with the terms of the indenture governing the notes, EFH Corp. will not be required to make a change of control offer to repurchase the notes under the indenture even if a change of control may otherwise have occurred.

The indenture governing the notes provides that a Permitted Asset Transfer may only occur if certain conditions are met, including a requirement that the ratings of the notes are not lowered by two or more rating agencies (or the only rating agency then rating such notes) during a specified period before or after the proposed Permitted Asset Transfer has been publicly announced. However, these conditions may not protect holders against actions that EFIH or the permitted transferee could take that may negatively impact the credit risk of the notes following a Permitted Asset Transfer, such as removing assets and cash from EFIH or the Oncor Subsidiaries or increasing debt at EFIH before the Permitted Asset Transfer. In addition, because EFIH is a “Restricted Subsidiary” under the indenture governing the notes, assets of EFIH, other than the Collateral, could be transferred to EFH Corp. prior to a Permitted Asset Transfer and would in that case not be assets of EFIH or a third party transferee that has become the obligor of the notes.

The third party transferee that becomes the obligor on the notes may itself engage in a subsequent Permitted Asset Transfer, in which case the risks described above would continue to apply with respect to the subsequent Permitted Asset Transfer and the subsequent third party transferee.

There is no event of default under the indenture governing the notes if the Oncor Subsidiaries take actions or enter into transactions that would impair their ability to dividend funds to EFIH, which could impair EFIH’s ability to make payments on the notes following a Permitted Asset Transfer, or that would negatively affect the value of the assets that are pledged as Collateral, such as incurring debt, selling or transferring all or a portion of the assets of Oncor, entering into joint ventures, dividending out assets or engaging in speculative investments.

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Any of the above actions on the part of EFIH, the third party transferee or subsequent third party transferee or the Oncor Subsidiaries following the completion of a Permitted Asset Transfer may further increase the credit risk of the notes, may result in the rating agencies taking negative action with respect to the notes and may reduce the market price of the notes.

See “Description of the Notes — Certain Covenants — Restrictions on Permitted Asset Transfers” and “Description of the Notes — Certain Covenants — Restrictions on TCEH Transfers” and the definitions of “Change of Control” and “Permitted Asset Transfer” contained under “Description of the Notes” for more information.

You may be required to recognize taxable gain or loss in connection with a Permitted Asset Transfer.

In connection with a Permitted Asset Transfer, EFH Corp.’s obligations under the notes would be transferred to, and assumed by, EFIH or a third party transferee or may be considered, for U.S. federal income tax purposes, to undergo a substitution of obligors even if not transferred to, or assumed by, a third party transferee. Upon any such transfer or deemed substitution of obligors, you may be deemed to have exchanged the notes for new notes for U.S. federal income tax purposes. Upon such deemed exchange, a holder, under U.S. federal income tax law, may be required to recognize gain or loss equal to the difference between the amount deemed to be realized in connection with the deemed exchange and such holder’s adjusted tax basis in the notes on the date of the deemed exchange.

We may transfer or dispose of our interests in or the assets of TCEH to a third party without such third party becoming the obligor under the notes and without being required to offer to repurchase the notes.

The indenture governing the notes provides that, subject to certain conditions, certain transactions with respect to TCEH, referred to in this prospectus as a “TCEH Transfer,” which include a disposition or spin-off of all of the equity interests of an entity that owns all or substantially all of the assets of TCEH (including EFCH), or the sale of all or substantially all of the assets of TCEH, will not result in the acquirer of the TCEH equity interests or assets becoming the obligor under the notes. The indenture governing the EFH Corp. Senior Secured Notes contains similar provisions.

If a TCEH Transfer occurs, EFH Corp. will remain the obligor of the notes and the EFH Corp. Senior Secured Notes, even though substantially all of the assets of EFH Corp. and its subsidiaries may have been transferred to a third party, and therefore EFH Corp. could be a more highly-leveraged company. Additionally, if a TCEH Transfer occurs, EFH Corp. will not be required to make a change of control offer to repurchase the notes, even if the assets of TCEH transferred accounted for substantially all of the assets of EFH Corp. and its subsidiaries. As of September 30, 2010, EFCH and its subsidiaries, including TCEH and its subsidiaries, accounted for approximately 83% of the consolidated assets of EFH Corp. The indenture governing the notes does not restrict EFH Corp.’s ability to transfer assets, other than Collateral, to any of its restricted subsidiaries, including EFCH and TCEH. EFH Corp. could take actions that may negatively impact the credit risk of the notes, including transferring assets to TCEH before a TCEH Transfer.

Currently, and for some period of time following the date of this prospectus, it is expected that EFH Corp. will rely on the cash flows from TCEH and its subsidiaries to service its debt obligations, including the notes. Following the completion of a TCEH Transfer, the cash flows from TCEH and its subsidiaries would no longer be available to pay interest and principal on the notes and the Senior Secured Notes. Additionally, the holders of the notes would not be able to look to the assets of TCEH and its subsidiaries in the case of a bankruptcy, liquidation or insolvency with respect to EFH Corp. In addition, EFH Corp. may transfer its interest in TCEH and its subsidiaries without any consideration if the transaction would not violate the “Limitation on Restricted Payments” covenant in the indenture governing the notes.

Additionally, following a TCEH Transfer, the only operating subsidiaries of EFH Corp. could be the Oncor Subsidiaries, which are “Unrestricted Subsidiaries” under the indenture governing the notes. Unrestricted Subsidiaries are not subject to the restrictive covenants contained in the indenture. The indenture governing the notes does not limit or restrict the ability of Unrestricted Subsidiaries, including the Oncor Subsidiaries, to take actions or enter into transactions that would impair their ability to dividend funds to EFH Corp. to make payments on the notes, or that would negatively affect the value of the Oncor Subsidiaries and therefore the equity value of the investments that are pledged as Collateral, such as incurring debt, selling or transferring all or a portion of the assets of the Oncor Subsidiaries, entering into joint ventures, dividending out assets or engaging in speculative investments.

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The occurrence of a TCEH Transfer may further increase the credit risk of the notes, may result in the credit rating agencies taking negative action with respect to the notes and may reduce the market price of the notes.

See “Description of the Notes — Certain Covenants — Restrictions on TCEH Transfers” and the definitions of “Change of Control” and “TCEH Transfer” contained under “Description of the Notes” for more information.

The indenture governing the notes may not protect holders from all actions that EFH Corp., EFIH or the Oncor Subsidiaries may take that would reduce your interest in the Collateral or that may reduce the value of the Collateral, including sales or exchanges of the Collateral or the assets of the Oncor Subsidiaries for other assets or investments.

Under the indenture governing the notes, EFIH may dispose of all or a portion of the Collateral for fair market value consideration (including consideration other than cash) that may consist of assets or equity interests in joint ventures. Additionally, there is no event of default under such indenture if the Oncor Subsidiaries sell, transfer or otherwise dispose of their assets or equity interests for any form of consideration.

If EFIH or the Oncor Subsidiaries effect any of these transactions, noteholders’ interest in the Collateral or the value of the Collateral may be materially reduced.

The indenture governing the notes allows EFIH to transfer any of the Collateral in exchange for an equivalent fair market value of assets other than cash or for investments in businesses that are similar to the businesses of Oncor, including interests in joint ventures in businesses that are not controlled by EFH Corp. or EFIH. The assets received as consideration and pledged as substitute Collateral may prove to be less valuable than the value of the investments in Oncor that were disposed of in such transfer or exchange. Additionally, if interests in a new business were received in exchange for the Collateral, such new business may, in the future, engage in businesses activities that are different from the business that Oncor presently is in or such new business may not prove to be as creditworthy or valuable as Oncor, and EFH Corp. may not have any control over such business’ activities if a minority interest in the joint venture interests was received in such transfer or exchange. Therefore, such new collateral may negatively alter the risk profile of EFIH or the value of such new collateral may decline relative to the value of the disposed investments in Oncor.

There is no event of default under the indenture governing the notes if any of the Oncor Subsidiaries sells, transfers or disposes of the assets of Oncor Holdings or investments in or assets of Oncor. The consideration received in exchange for such assets or investments may decline in value as compared to the assets or investments that were so disposed, and, therefore, the value of the Collateral may be less than if such assets and investments had been retained. The Oncor Subsidiaries may transfer their assets and investments in exchange for interests in other businesses or assets, minority interests or interests in joint ventures, in which case the value of the Collateral may be at risk of declining due to the factors described above.

In any joint venture in which EFIH or an Oncor Subsidiary has an interest, EFIH or the Oncor Subsidiary may not have the right or power to direct the management and policies of such joint ventures and other participants may take action contrary to the instructions or requests of EFIH or such Oncor Subsidiary or against its policies and objectives, and any such actions taken by such joint ventures may not be in the best interests of holders of notes. In addition, the other participants to any such joint venture may become bankrupt or have economic or other business interests or goals that are inconsistent with the goals of EFIH or such Oncor Subsidiary and/or the holders of the notes.

Additionally, the TCEH Senior Secured Facilities do not allow EFH Corp. to prepay the notes using proceeds received from a disposition of any investments of EFH Corp. and EFIH in the Oncor Subsidiaries (including the Collateral) or from a sale of all or substantially all of the assets of any of the Oncor Subsidiaries, so long as certain intercompany loans from TCEH to EFH Corp. are at the time outstanding. As of September 30, 2010, $1.690 billion of such intercompany loans from TCEH to EFH Corp. were outstanding.

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The completion of any of the above events may result in the credit risk of the notes increasing, the credit rating agencies taking negative action with respect to the notes or the market price of the notes declining. Additionally, in the event of any foreclosure on the Collateral, holders of the notes may recover less than if the Collateral still consisted of investments in the Oncor Subsidiaries.

The liabilities of each of EFH Corp. and EFCH currently exceed its assets as shown on its most recent quarterly balance sheet. If a court were to find that EFH Corp., EFCH or EFIH were insolvent before or after giving effect to the offering of the notes and did not receive reasonably equivalent value or fair consideration for the issuance of the notes or the incurrence of a guarantee or the pledge of the Collateral, as applicable, the court may void all or a portion of the obligations represented by the notes or the guarantee of the notes by EFCH or EFIH or the pledge of the Collateral by EFIH as a fraudulent conveyance.

In a bankruptcy proceeding, a trustee, debtor in possession or another person acting on behalf of the bankruptcy estate may seek to recover all or a portion of transfers made or void obligations incurred prior to the bankruptcy proceeding on the basis that such transfers and obligations constituted fraudulent conveyances. Under certain circumstances, creditors may recover transfers or void obligations under state fraudulent conveyance laws even if the debtor is not in bankruptcy.

Fraudulent conveyances are generally defined to include transfers made or obligations incurred for inadequate consideration when a debtor was insolvent, inadequately capitalized or in similar financial distress, or transfers made or obligations incurred with the intent of hindering, delaying or defrauding current or future creditors. A trustee, debtor in possession or another person acting on behalf of a bankruptcy estate may be able to recover such transfers under the fraudulent conveyance provisions of the bankruptcy law and/or state fraudulent conveyance laws. The fraudulent conveyance provisions of the bankruptcy law allows the trustee, debtor in possession, or other person acting on behalf of a bankruptcy estate to void a fraudulent conveyance made within two years prior to the commencement of a bankruptcy proceeding. Under state fraudulent conveyance laws, transfers made more than two years prior to the commencement of a fraudulent conveyance lawsuit may be subject to avoidance.

If a court were to find that EFH Corp. issued the notes or EFCH or EFIH issued its respective guarantee, or EFIH granted its pledge of the Collateral, under circumstances constituting a fraudulent conveyance, then a court could void all or a portion of the obligations under the notes, such guarantee or the pledge of the Collateral. In addition, under such circumstances, the value of any consideration holders received with respect to the notes, such guarantee, and the Collateral, including upon foreclosure of the Collateral, could also be subject to recovery from such holders and, possibly, from subsequent transferees of the notes. If the pledge of Collateral was voided and the issuance of the notes and/or the related guarantees were not voided, then holders of notes would become unsecured creditors.

The notes or the related guarantees incurred by EFCH or EFIH or the pledge of the Collateral by EFIH could be voided as a fraudulent conveyance, or claims in respect of the notes, such guarantee or pledge could be subordinated to all other debts of EFH Corp., EFCH or EFIH, if EFH Corp., EFCH or EFIH, at the time they incurred the indebtedness evidenced by the notes or such guarantee or granted the pledge received less than reasonably equivalent value or fair consideration for the issuance of the notes or the incurrence of such guarantee and:

• were insolvent or rendered insolvent by reason of such issuance or incurrence;

• were engaged in a business or transaction for which our or EFCH’s or EFIH’s remaining assets constituted unreasonably small capital; or

• intended to incur, or believed that they would incur, debts beyond their ability to pay those debts as they mature.

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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 debtor 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;

• 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.

The liabilities of each of EFH Corp. and EFCH currently exceed its assets as shown on its respective balance sheet prepared in accordance with U.S. GAAP as of September 30, 2010. The balance sheets showing the assets and liabilities of EFH Corp. and EFCH have been prepared in accordance with U.S. GAAP; however, the values assigned to assets and liabilities in these balance sheets are not necessarily indicative of the values that a court would assign to such assets and liabilities in making a solvency determination. We cannot assure you that EFH Corp., EFCH or EFIH would satisfy the solvency tests set forth in the bullet points immediately prior to this paragraph or what standard a court would apply in determining whether EFH Corp., EFCH or EFIH would be considered to be insolvent.

In addition, we cannot assure you that a court would determine that reasonably equivalent value or fair consideration was received by each of EFH Corp., EFCH and EFIH in connection with the offering of the notes and the incurrence of the guarantee or pledge, as applicable. EFIH did not receive any of the proceeds from the offering of the notes.

Each guarantee of the notes 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 conveyance. This provision may not be effective to protect the guarantee from being voided under fraudulent conveyance law, or may reduce or eliminate the guarantor’s obligation to an amount that effectively makes the guarantee worthless.

The majority of our subsidiaries do not guarantee the notes. As a result, the notes are structurally subordinated to all liabilities of our subsidiaries that do not guarantee the notes.

The notes are guaranteed on a senior secured basis by EFIH and on a senior unsecured basis by EFCH, but the notes are not guaranteed by any of EFH Corp.’s other subsidiaries. None of EFH Corp., EFIH or EFCH has any operations, and each relies on distributions from its subsidiaries. However, EFH Corp.’s historical consolidated financial statements reflect the results of operations and assets, among other things, of all of EFH Corp.’s subsidiaries (or EFH Corp.’s interest in such results of operations or assets in the case of the Oncor Subsidiaries). EFH Corp.’s non-guarantor subsidiaries generated all of its consolidated revenues for the year ended December 31, 2009 and for the nine months ended September 30, 2010, and as of September 30, 2010, EFH Corp.’s non-guarantor subsidiaries represented substantially all of its consolidated total assets.

EFH Corp.’s non-guarantor subsidiaries (including Oncor Holdings and Oncor and its 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. The notes are structurally subordinated to indebtedness and other liabilities of EFH Corp.’s subsidiaries that do not guarantee the notes. The claims of creditors of each of the non-guarantor subsidiaries, including trade creditors, have priority as to the assets of these subsidiaries. In the event of a bankruptcy, liquidation or insolvency of any of these subsidiaries, these subsidiaries will pay the holders of their debts, holders of preferred equity interests and their trade creditors before they will be able to distribute any of their assets to EFH Corp. In addition, the guarantee of the notes by EFCH is structurally subordinated to the indebtedness of TCEH, the principal amount of which, as of September 30, 2010, was $30.282 billion (including long-term debt, including amounts due currently and $427 million principal amount held by EFH Corp. and EFIH, and short-term borrowings), as well as any other indebtedness of the other subsidiaries of EFCH. See Note 26 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 and Note 17 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for financial information regarding EFH Corp.’s subsidiaries. Additionally, EFH Corp. may be able to designate each of EFCH and TCEH as an “Unrestricted Subsidiary” under the indenture that governs the notes. If they are so designated, EFCH and TCEH will not be subject to the restrictive covenants contained in the indenture governing the notes, and EFCH’s guarantee of the notes will be released.

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The interests of the Sponsor Group may differ from the interests of the holders of the notes.

The Sponsor Group indirectly owns approximately 60% of EFH Corp.’s capital stock on a fully diluted basis through their investment in Texas Holdings. As a result of this ownership and the Sponsor Group’s ownership in interests of the general partner of Texas Holdings, the Sponsor Group has control over decisions regarding our operations, plans, strategies, finances and structure, including whether to enter into any corporate transaction, and will have the ability to prevent any transaction that requires the approval of EFH Corp.’s shareholders.

The 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 noteholder. 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 noteholder. 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.

Risks Related to Substantial 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 obligations under the various debt agreements governing our indebtedness.

We are highly leveraged. As of September 30, 2010, our consolidated principal amount of debt (short-term borrowings and long-term debt, including amounts due currently) totaled $36.348 billion (see Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 included elsewhere in this prospectus and Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 included elsewhere in this prospectus), which does not include $5.956 billion principal amount of debt of the Oncor Subsidiaries that has been deconsolidated. 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, as of September 30, 2010, taking into consideration interest swap transactions, 11% of our long-term borrowings were at variable rates of interest;

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

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

• 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 we cannot due to our substantial leverage.

A substantial amount of this indebtedness is comprised of our indebtedness under the TCEH Senior Secured Facilities, substantially all of which matures in October 2014. We may not be able to refinance the TCEH Senior Secured Facilities or its other existing indebtedness because of our high levels of debt and debt incurrence restrictions under our debt agreements or because of generally adverse conditions in credit markets.

As of September 30, 2010, we have effectively hedged an estimated 64% of the natural gas price exposure related to our expected generation output for the period from October 1, 2010 through December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate) under our long term hedging program. However, forward natural gas prices have generally trended downward since mid-2008. While our long-term hedging program is designed to mitigate the effect on earnings of low wholesale power prices, due to low natural gas prices, these market conditions are challenging to the long-term profitability of our generation assets. Specifically, these lower natural gas prices and the correlated effect in ERCOT on wholesale power prices could have a material adverse impact on the overall profitability of our generation assets for periods in which we do not have significant hedge positions. A continuation or worsening of these market conditions could limit our ability to hedge our wholesale power revenues at sufficient price levels to support our interest payments and debt maturities and could adversely impact our ability to refinance our substantial debt due in 2014.

While we expect to be able to repay a portion of our debt obligations through cash flow from operations, we may not be able to repay or refinance all outstanding amounts as or before they become due, or may be able to refinance such amounts only on terms that will increase our cost of borrowing or on terms that may be more onerous. Our ability to successfully implement any future refinancing of our debt will depend on our and our subsidiaries’ financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control, including, without limitation, wholesale power prices in ERCOT (which are primarily driven by the price of natural gas and ERCOT market heat rates).

We may also need to raise additional capital by raising additional debt, such as secured or unsecured high yield debt, on terms that may increase our cost of borrowing or result in more onerous terms or selling or disposing of some of our assets, possibly on unfavorable terms. We cannot assure you that any of, or any combination of, the above actions would be available or sufficient to fund our debt, that we will be able to refinance our debt as or before it comes due, or that we will be able to obtain additional financing on favorable terms or at all, should the need arise.

In addition, future transactions and initiatives that we continuously contemplate and may pursue may have significant effects on our business, capital structure, liquidity and/or results of operations. For example, in addition to the exchanges and repurchases of our debt that are described in Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 included elsewhere in this prospectus, we have and may continue to pursue, from time to time, transactions and initiatives of various types, including, without limitation, other exchange transactions, debt repurchases, equity or debt issuances, asset sales, joint ventures, recapitalizations, business combinations and other strategic transactions. There can be no guarantee that any of such transactions or initiatives would ultimately be successful or produce the desired outcome, which could ultimately affect us in a material and adverse manner. Moreover, the effects of any of these transactions or initiatives could be material and adverse to holders of our debt and could be disproportionate, and directionally different, with respect to one class or type of debt than with respect to others.

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, including secured indebtedness, that could be incurred in compliance with these restrictions could be substantial. The indenture governing the notes allows EFH Corp. to incur up to an aggregate of $4.0 billion of debt, including the Senior Secured Notes and the notes, which would be secured on a parity lien basis by the Collateral, and a substantial amount of additional indebtedness, which additional indebtedness may be secured by a junior-priority security interest in the Collateral or by assets of EFH Corp. or EFIH other than the Collateral. If new debt is added to our existing debt levels, the related risks that we now face would intensify. See “Description of the Notes.”

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

Certain of our borrowings are at variable rates of interest. To the extent the interest rate for such borrowings is not fixed by interest rate swaps, 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, 2010, we had $4.045 billion aggregate principal amount of variable rate long-term indebtedness (excluding $1.135 billion of long-term borrowings associated with the senior secured letter of credit facility of TCEH that are invested at a variable rate), taking into account interest rate swaps that fix the interest rate on $16.3 billion in notional amount of variable rate indebtedness. As a result, as of September 30, 2010, the impact of a 100 basis point increase in interest rates would increase our annual interest expense by approximately $40 million. See discussion of interest rate swap transactions in Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010.

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Interest expense and related charges for the nine months ended September 30, 2010 totaled $3.092 billion, including $542 million of unrealized mark-to-market net losses on interest rate swaps.

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

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

• incur additional 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 or our subsidiaries’ assets;

• enter into transactions with affiliates; and

• repay, repurchase or modify certain subordinated and other material debt.

There are a number of important limitations and exceptions to these covenants and other restrictions. See “Description of the Notes” for a description of these covenants and other restrictions with respect to the exchange notes.

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/or 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.

In addition, EFH Corp. and Oncor have implemented a number of “ring-fencing” measures to enhance the credit quality of Oncor, its immediate parent, Oncor Holdings, and Oncor Holdings’ other subsidiaries. Those measures include, among other things:

• Oncor being treated as an unrestricted subsidiary with respect to EFH Corp.’s indebtedness;

• Oncor not being restricted from incurring its own indebtedness;

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

• restrictions on dividends, and the right of the independent members of Oncor’s board of directors and the primary noncontrolling member of Oncor to block the payment of dividends.

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Under the terms of the indentures governing the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes and the TCEH Senior Secured Facilities, 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, 2010, TCEH and its subsidiaries held approximately 83% of EFH Corp.’s consolidated assets and for the nine months ended September 30, 2010, TCEH and its subsidiaries represented all of EFH Corp.’s consolidated revenues. Accordingly, EFH Corp. depends upon TCEH for a significant amount of its cash flows and ability to pay its obligations, including its obligations under the notes. However, under the terms of the indentures governing the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities, TCEH is restricted from making certain payments to EFH Corp., except in the form of certain loans to cover certain of EFH Corp.’s obligations and dividends and distributions in certain other limited circumstances if permitted by applicable state law. Further, the indentures governing the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities do not permit such intercompany loans to service EFH Corp. debt unless required for EFH Corp. to pay principal, premium and interest when due on indebtedness incurred by EFH Corp. to finance the Merger or that was in existence prior to the Merger, or any indebtedness incurred by EFH Corp. to replace, refund or refinance such debt. Such loans are also permitted to service other debt, subject to limitations on the amount of the loans. In addition, TCEH is prohibited from making certain loans to EFH Corp. if certain events of default under the indentures governing the TCEH Senior Notes or the TCEH Senior Secured Second Lien Notes or the terms of the TCEH Senior Secured Facilities have occurred and are continuing.

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

EFH Corp. is a holding company and substantially all of its consolidated assets are held by its subsidiaries. As of September 30, 2010, EFIH and its subsidiaries held approximately 12% of EFH Corp.’s consolidated assets, primarily reflecting the investment in the Oncor Subsidiaries. Accordingly, EFH Corp. depends upon EFIH for a significant amount of its cash flows and ability to pay its obligations. However, under the terms of the indenture governing the EFIH Notes, EFIH is restricted from making certain payments, including dividends and loans, to EFH Corp., except in limited circumstances.

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

EFH Corp. depends upon Oncor for a significant amount of its cash flows and ability to pay its obligations. However, EFH Corp. has a very limited ability to control the activities of Oncor. As part of the “ring-fencing” measures implemented by EFH Corp. and Oncor, a majority of the members of Oncor’s board of directors are required to meet the New York Stock Exchange requirements for independence in all material respects, and the unanimous consent of such directors is required for Oncor to take certain actions. In addition, any new independent directors are required to be appointed by the nominating committee of Oncor Holdings’ board of directors, a majority of whose members are independent directors. No member of EFH Corp.’s management is a member of Oncor’s board of directors. Under Oncor Holdings’ and Oncor’s organizational documents, EFH Corp. has the right, indirectly, to consent to new issuances of equity securities by Oncor, material transactions with third parties involving Oncor outside of the ordinary course of business, actions that cause Oncor’s assets to increase the level of jurisdiction of the FERC, any changes to the state of formation of Oncor, material changes to accounting methods not required by U.S. GAAP, and actions that fail to enforce certain tax sharing obligations between Oncor and EFH Corp. In addition, there are restrictions on Oncor’s ability to make distributions to its members, including indirectly to EFH Corp.

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Risks Related to Structure

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

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

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

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

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

As part of the ring-fencing measures, a majority of the members of the board of directors of Oncor are required to be, and are, independent from EFH Corp. Any new independent directors of Oncor are required to be appointed by the nominating committee of Oncor Holdings. The organizational documents of Oncor give these independent directors, acting by majority vote, and, during certain periods, any director designated by Texas Transmission, the express right to prevent distributions from Oncor if they determine that it is in the best interests of Oncor to retain such amounts to meet expected future requirements. Accordingly, there can be no assurance that Oncor will make any distributions to EFH Corp.

In addition, Oncor’s organizational documents limit Oncor’s distributions to its owners, including EFH Corp. through December 31, 2012 to an amount not to exceed Oncor’s net income (determined in accordance with U.S. GAAP, subject to certain defined adjustments, including goodwill impairments) and prohibit Oncor from making any distribution to EFH Corp. so long as and to the extent that such distribution would cause Oncor’s regulatory capital structure to exceed the debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.

In March 2009, the PUCT awarded Oncor the right to construct approximately $1.3 billion (currently estimated to be approximately $1.75 billion) of transmission lines and facilities associated with its CREZ Transmission Plan (see discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operations for the Three and Nine Months Ended September 30, 2010 — Regulation and Rates”). With the award, it is likely Oncor will incur additional debt. In addition, Oncor may incur additional debt in connection with other investments in infrastructure or technology. Accordingly, while Oncor is required to maintain a debt-to-equity ratio of 60% debt to 40% equity, there can be no assurance that Oncor’s equity balance will be sufficient to maintain the required debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, thereby restricting Oncor from making any distributions to EFH Corp.

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Risks Related to Our Businesses

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

Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory initiatives regarding the restructuring of the energy industry, including competition in the generation and sale of electricity. We will need to continually adapt to these changes.

Our businesses are subject to changes in state and federal laws (including PURA, the Federal Power Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act and the Energy Policy Act of 2005), changing governmental policy and regulatory actions (including those of the PUCT, the NERC, the TRE, the RRC, the TCEQ, the FERC, the EPA, the NRC and the CFTC) and the rules, guidelines and protocols of ERCOT with respect to matters including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, construction and operation of transmission facilities, acquisition, disposal, depreciation and amortization of regulated assets and facilities, recovery of costs and investments, decommissioning costs, return on invested capital for regulated businesses, market behavior rules, present or prospective wholesale and retail competition and environmental matters. TCEH, along with other market participants, is subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA that are administered by the PUCT and ERCOT, and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior and other competition-related rules and regulations under the Federal Power Act that are administered by the FERC. Changes in, revisions to, or reinterpretations of existing laws and regulations (for example, with respect to prices at which TCEH may sell electricity, the required permits for the three lignite-fueled generation units recently completed or the cost of emitting greenhouse gases) may have an adverse effect on our businesses.

The Texas Legislature meets every two years (the next legislative session begins in January 2011), and from time to time bills are introduced and considered that could materially affect our businesses. There can be no assurance that future action of the Texas Legislature will not result in legislation that could have a material adverse effect on us and our financial prospects.

PURA, the PUCT, ERCOT, the RRC, the TCEQ and the Office of Public Utility Council (OPC) are subject to a “Sunset” review by the Texas Sunset Advisory Commission. PURA will expire, and the PUCT and the RRC will be abolished, on September 1, 2011 unless extended by the Texas Legislature following such review. If any of PURA, the PUCT, ERCOT, the RRC, the TCEQ or the OPC are not renewed by the Texas Legislature pursuant to Sunset review, it could have a material effect on our business.

Sunset review is the regular assessment of the continuing need for a state agency to exist, and is grounded in the premise that an agency will be abolished unless legislation is passed to continue its functions. The Texas Sunset Advisory Commission (Sunset Commission) closely reviews each agency and recommends action on each agency to the Texas Legislature, which action may include modifying or even abolishing the agency. Of the agencies scheduled for Sunset review by the Sunset Commission in 2010 and 2011, the following hold primary interest for us: the TCEQ, the PUCT, the OPC, the RRC and ERCOT, which are subject to a focused, limited scope, or special purpose review. These agencies, for the most part, govern and operate the electricity and mining markets in Texas upon which our business model is based. PURA, which expires September 1, 2011, is also subject to Sunset review. If the Texas Legislature fails to renew PURA or any of these agencies, it could result in a significant restructuring of the Texas electricity market or regulatory regime that could have a material impact on our business. There can be no assurance that future action of the Sunset Commission will not result in legislation that could have a material adverse effect on us and our financial prospects.

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Litigation, legal proceedings, regulatory investigations or other administrative 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. 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 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 appropriate means to contest litigation threatened or filed against us, but the litigation environment in the State of Texas poses a significant business risk.

We are involved in the ordinary course of business in permit applications and renewals, and we are exposed to the risk that certain of our operating permits may not be granted or renewed on satisfactory terms. Failure to obtain and maintain the necessary permits to conduct our businesses could have a material adverse effect on our results of operations.

We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings. See Note 7 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 included elsewhere in this prospectus. While we cannot predict the outcome of any regulatory investigation or administrative proceeding, any such regulatory investigation or administrative proceeding could result in us incurring material penalties and/or other costs and have a material adverse effect on our results of operations.

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

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

In some retail electricity 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, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with TXU Energy. Some of these competitors or potential competitors may be larger or better capitalized than TXU Energy. If there is inadequate potential margin in these retail electricity markets, it may not be profitable for TXU Energy to compete in these markets.

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

TCEH (EFH Corp.’s largest business) is not guaranteed any rate of return on capital investments in its competitive businesses. We market and trade electricity and natural gas, including electricity from our own generation facilities and generation contracted from third parties, as part of our wholesale markets operation. TCEH’s results of operations depend in large part upon market prices for electricity, natural gas, uranium, coal and transportation in its regional market and other competitive markets and upon prevailing retail electricity rates, which may be impacted by actions of regulatory authorities. Market prices may fluctuate substantially over relatively short periods of time. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, at times there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets.

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Some of the fuel for our generation facilities is purchased under short-term contracts. Prices of fuel, including diesel, natural gas, coal and nuclear fuel, may also be volatile, and the price we can obtain for electricity sales may not change at the same rate as changes in fuel costs. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting obligations.

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

• volatility in natural gas prices;

• volatility in market heat rates;

• volatility in coal and rail transportation prices;

• severe or unexpected weather conditions;

• seasonality;

• changes in electricity and fuel usage;

• illiquidity in the wholesale power or other markets;

• transmission or transportation constraints, inoperability or inefficiencies;

• availability of competitively-priced alternative energy sources;

• changes in market structure;

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

• changes in generation efficiency;

• outages at our generation facilities or those of our competitors;

• changes in the credit risk or payment practices of market participants;

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

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

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

All of our generation facilities are located in the ERCOT market, a market with limited interconnections to other markets. Wholesale electricity prices in the ERCOT market generally correlate with the price of natural gas because marginal electricity demand is generally supplied by natural gas-fueled generation facilities.

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 our baseload (lignite/coal-fueled and nuclear) generation assets, which provided a substantial portion of our supply volumes in 2009 and in 2010 to date, are dependent in significant part upon the price of natural gas and market heat rates. As a result, our baseload generation assets could significantly decrease in profitability and value if natural gas prices or market heat rates fall.

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

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

To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portions of purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, crude oil, diesel fuel and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Although we devote a considerable amount of time and effort to the establishment of risk management procedures, as well as the ongoing review of the implementation of these procedures, the procedures in place may not always function as planned and cannot eliminate all the risks associated with these activities. For example, we hedge the expected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters, market constraints or other factors could cause us to purchase power to meet unexpected demand in periods of high wholesale market prices or resell excess power into the wholesale market in periods of low prices. As a result of these and other factors, we cannot precisely predict the impact that risk management decisions may have on our businesses, results of operations or financial position.

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

To the extent we engage in hedging and risk management activities, we are exposed to the risk that counterparties that owe us money, energy or other commodities as a result of 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 on its obligations to pay ERCOT for power taken, in which case such costs, to the extent not offset by posted security and other protections available to ERCOT, may be allocated to various non-defaulting ERCOT market participants, including us.

Our collateral requirements for hedging arrangements could be materially impacted if the rules implementing the Financial Reform Act broaden the scope of the Act’s provisions regarding the regulation of over-the-counter financial derivatives and make them applicable to us.

In July 2010, the U.S. Congress enacted, and President Obama signed, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Financial Reform Act”). Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives market. While the legislation is broad and detailed, substantial portions of the legislation will require rulemaking by federal governmental agencies to either implement the standards set out in the legislation or to adopt new standards.

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The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that we use to hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However, end-users that are non-financial entities using the swap to hedge or mitigate commercial risk are exempt from these clearing requirements. The type of asset-backed OTC derivatives that we use to hedge commodity and interest rate risk should be exempt from the clearing requirements. In addition, existing swaps are grandfathered from the clearing requirements.

The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. Because these cash collateral requirements are unclear as to whether an end-user or its counterparty (i.e., swap dealer) is required to post cash collateral, there is risk that the cash collateral requirement could be used to effectively negate the end-user clearing exemption. However, the legislative history of the Financial Reform Act suggests that it was not Congress’ intent to require end-users (rather that such requirement apply to swap dealers) to post cash collateral with respect to swaps. If we were required to post cash collateral on our swap transactions, our liquidity would likely be materially impacted, and our ability to enter into OTC derivatives to hedge our commodity and interest rate risks would be significantly limited.

We cannot predict the outcome of the rulemaking to implement the OTC derivative market provisions of the Financial Reform Act. This rulemaking could negatively affect our ability to hedge our commodity and interest rate risks. The inability to hedge these risks would likely have a material adverse effect on our results of operations, financial condition or cash flows.

We may suffer material losses, costs and liabilities due to ownership and operation of the Comanche Peak nuclear generation facility.

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

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

• inadequacy or lapses in maintenance protocols;

• the impairment of reactor operation and safety systems due to human error;

• the costs of storage, handling and disposal of nuclear materials, including availability of storage space;

• the costs of procuring nuclear fuel;

• the costs of securing the plant against possible terrorist attacks;

• limitations on the amounts and types of insurance coverage commercially available; and

• uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives.

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

• Operational Risk — Operations at any nuclear generation facility could degrade to the point where the facility would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availability at Comanche Peak.

• Regulatory Risk — The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unless extended, the NRC operating licenses for Comanche Peak Unit 1 and Unit 2 will expire in 2030 and 2033, respectively. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.

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• Nuclear Accident Risk — Although the safety record of Comanche Peak and other nuclear generation facilities generally has been very good, accidents and other unforeseen problems have occurred both in the 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.

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 financial condition, liquidity and results of operations.

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

The EPA has recently completed several regulatory actions establishing new requirements for control of certain emissions from sources that include coal-fueled generation facilities. It is also currently considering several other regulatory actions, as well as contemplating future additional regulatory actions, in each case that may affect our coal-fueled generation facilities. There is no assurance that the currently-installed emissions control equipment at our coal-fueled generation facilities will satisfy the requirements under any future EPA or TCEQ regulations. Some of the potential EPA or TCEQ regulatory actions could require us to install significant additional control equipment, resulting in material costs of compliance for our generation units, including capital expenditures and higher operating costs. These costs could result in material adverse effects on our financial condition, liquidity and results of operations.

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In conjunction with the building of three new generation units, we have committed to reduce emissions of mercury, nitrogen oxide (NO_x) and sulfur dioxide (SO₂) through the installation of emissions control equipment at both the new and existing and lignite-fueled generation units. 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. Any 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.

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

In recent years, a growing concern has emerged about global climate change and how greenhouse gas (GHG) emissions, such as carbon dioxide (CO₂), contribute to global climate change. Several bills addressing climate change have been introduced in the U.S. Congress or discussed by the Obama Administration that are intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), incentives for the development of low-carbon technology and federal renewable portfolio standards. In addition, a number of federal court cases have been recently decided that could result in the future judicial regulation of GHG emissions.

The EPA recently issued a rule, known as the Prevention of Significant Deterioration (PSD) tailoring rule, that establishes new thresholds for regulating GHG emissions from stationary sources under the Clean Air Act. Beginning in January 2011, the rule will require any source subject to the PSD permitting program due to emissions of non-GHG pollutants that increases its GHG emissions by 75,000 tons per year (tpy) to have an operating permit under the Title V Operating Permit Program of the Clean Air Act and install the best available control technology in conjunction with construction activities or plant modifications. Beginning in July 2011, PSD permitting requirements will also apply to new projects with GHG emissions of at least 100,000 tpy and modifications to existing facilities that increase GHG emissions by at least 75,000 tpy (even if no non-GHG PSD thresholds are exceeded). The EPA also finalized regulations in 2009 that will require certain categories of GHG emitters to monitor and report their annual GHG emissions beginning in January 2011.

We produce GHG emissions from the combustion of fossil fuels at our generation facilities. For 2009, we estimate that our generation facilities produced 54 million short tons of carbon dioxide based on continuously monitored data reported to and approved by the EPA. The two new lignite-fueled units that achieved substantial completion (as defined in the engineering, procurement and construction (EPC) agreements for the units) in 2009 and the one new lignite-fueled unit that achieved substantial completion (as defined in the EPC agreement for the unit) in June 2010 will generate additional carbon dioxide emissions. Because a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities, our financial condition and results of operations could be materially adversely affected by the enactment of any legislation or regulation that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes upon those that produce GHG emissions. For example, to the extent a cap-and-trade program is adopted, we may be required to incur material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with such a program. The EPA regulation of GHGs under the Clean Air Act, or judicially imposed limits on GHG emissions, may require us to make material expenditures to reduce our GHG emissions. If a significant number of our investors, customers or others refuse to do business with us because of our GHG emissions, it could have a material adverse effect on our results of operations, financial condition or cash flows.

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Our financial condition and results of operations may be materially adversely affected by the effects of extreme weather conditions.

We could be subject to the effects of extreme weather. Extreme weather conditions could stress our transmission and distribution system or our generation facilities resulting in increased maintenance and capital expenditures. Extreme weather events, including hurricanes or storms or other natural disasters, could be destructive and result in casualty losses that are not ultimately offset by insurance proceeds or in increased capital expenditures or costs, including supply chain costs.

Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, an extreme weather event might affect the availability of generation and transmission capacity, limiting our ability to source or deliver electricity to where it is needed. These conditions, which cannot be reliably predicted, could have an adverse consequence by requiring us to seek additional sources of electricity when wholesale market prices are high or to seek to sell excess electricity when those market prices are low.

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

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 Oncor’s balance sheet, and the return on invested capital allowed by the PUCT. Oncor expects to file with the PUCT for a regulatory review of its rates in January 2011.

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

Our growth strategy 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.

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There can be no guarantee that the execution of Oncor’s capital deployment program for its electricity delivery facilities will be successful, and there can be no assurance that the capital investments Oncor intends to make in connection with its electricity delivery business will produce the desired reductions in cost and improvements to service and reliability. Furthermore, there can be no guarantee that Oncor’s capital investments, including the investment of approximately $1.75 billion to construct CREZ-related transmission lines and facilities, will ultimately be recoverable through rates or, if recovered, that they will be recovered on a timely basis. There can also be no assurance that the PUCT’s award of CREZ construction projects will not be delayed, modified or otherwise vacated through judicial or administrative actions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010 — Regulation and Rates” included elsewhere in this prospectus.

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 if unsuccessful, may instead result in significant additional costs as well as significant disruptions in our operations due to employee displacement and the rapid pace of changes to organizational structure and operating practices and processes. Such additional costs or operational disruptions could have an adverse effect on our businesses 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.

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.

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

The PUCT may at any time initiate an investigation into whether TXU Energy is compliant with PUCT Substantive Rules and whether it has met all of the requirements for REP certification, including financial requirements. Any removal or revocation of a REP certification would mean that TXU Energy would no longer be allowed to provide electricity service to retail customers. Such decertification would have an adverse effect on TXU Energy and its financial prospects. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010 — Regulations and Rates” included elsewhere in this prospectus for a discussion of new rules regarding REP certification.

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

Research and development activities are ongoing to improve existing and alternative technologies to produce electricity, including gas turbines, fuel cells, microturbines, photovoltaic (solar) cells and concentrated solar thermal devices. It is possible that advances in these or other technologies will reduce the costs of electricity production from these technologies to a level that will enable these technologies to compete effectively with our traditional generation plants. While demand for electricity has been generally increasing throughout the U.S., the rate of construction and development of new, more efficient generation facilities may exceed increases 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. Changes in technology could also alter the channels through which retail customers buy electricity. To the extent self-generation facilities become a more cost-effective option for certain customers, our revenues could be materially reduced.

Also, electricity demand could be reduced by increased conservation efforts and advances in technology, which could likewise significantly reduce the value of our generation assets and electricity delivery facilities. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Effective energy conservation by our customers could result in reduced energy demand or significantly slow the growth in demand. Such reduction in demand could materially reduce our revenues. Furthermore, we may incur increased capital expenditures if we are required to invest in conservation measures.

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 ERCOT 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, has been impacted and could be further impacted by the effects of the wind power generation, and the value could significantly decrease if wind power generation has a material sustained effect on market heat rates.

Our revenues and results of operations may be adversely impacted as ERCOT transitions from a 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 transitioning from a zonal market structure with four congestion management zones to a nodal market structure that directly manages congestion on a localized basis. In a nodal market, the prices received and paid for power are 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. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010 — Regulations and Rates — Wholesale Market Design” included elsewhere in this prospectus.

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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.

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

Downgrades in EFH Corp.’s or any of its applicable subsidiaries’ long-term debt ratings generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease and could trigger liquidity demands pursuant to the terms of new commodity contracts, leases or other agreements. Future transactions by EFH Corp. or any of its subsidiaries, including the issuance of additional debt or the consummation of debt exchanges, could result in temporary or permanent downgrades of EFH Corp.’s or its subsidiaries’ credit ratings.

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

Continued market volatility may have impacts on our businesses and financial condition that we currently cannot predict.

Because our operations are capital intensive, we expect to rely over the long-term upon access to financial markets (particularly the attainment of liquidity facilities) as a significant source of liquidity for capital requirements not satisfied by cash-on-hand, operating cash flows or our revolving credit facilities. Recently, the capital and credit markets have been experiencing extreme volatility and disruption. Our ability to access the capital or credit markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. In addition, the cost of debt financing may be materially impacted by these market conditions. Accordingly, there can be no assurance that the capital and credit markets will continue to be a reliable or acceptable source of short-term or long-term financing for us. Additionally, disruptions in the capital and credit markets could have a broader impact on the economy in general in ways that could lead to reduced electricity usage, which could have a negative impact on our revenues, or have an impact on our customers, counterparties and/or lenders, causing them to fail to meet their obligations to us.

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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 rely on access to financial markets and liquidity facilities as a significant source of liquidity for capital requirements not satisfied by cash-on-hand or operating cash flows. The inability to raise capital on favorable terms or access liquidity facilities, particularly during times of uncertainty similar to that which has recently been 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 and liquidity facilities could be adversely impacted by various factors, such as:

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

• economic weakness in the ERCOT or general U.S. market;

• changes in interest rates;

• a deterioration of our credit or a reduction in our credit ratings;

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

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

• a material breakdown in our risk management procedures; and

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

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 us being required to provide cash or letter of credit collateral in substantial amounts. While these potential posting obligations are primarily supported by the liquidity facilities, for certain transactions there is a potential for the timing of postings on the commodity contract obligations to vary from the timing of borrowings from the senior secured cash posting credit facility of TCEH. Any perceived reduction in our credit quality could result in clearing agents or other counterparties requesting additional collateral. We have credit concentration risk related to the limited number of lenders that provide liquidity to support our hedging program. A deterioration of the credit quality of such lenders could materially affect our ability to continue such program on acceptable terms. An event of default by one or more of our hedge counterparties could result in termination-related settlement payments that reduce available liquidity if we owe amounts related to commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us. These events could have a material negative impact on our financial condition and results of operations.

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.

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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 OPEB 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 us. Our costs of providing such benefits and related funding requirements are dependent upon numerous factors, assumptions and estimates and are subject to changes in these factors, assumptions and estimates, including the market value of the assets funding our pension and OPEB plans. Fluctuations in financial market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.

The substantial dislocation in the financial markets that began in 2008 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 the pension plan and the costs of the OPEB plans and related funding requirements in the future. Our costs of providing such benefits and related funding requirements are also subject to changing employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in financial market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.

As was the case in the third quarter 2010 (as discussed in Note 4 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 included elsewhere in this prospectus), goodwill and/or other intangible assets not subject to amortization that we have recorded in connection with the Merger are subject to at least annual impairment evaluations, and as a result, we could be required to write off some or all of this goodwill and other intangible assets, which may cause adverse impacts on our financial condition and results of operations.

In accordance with accounting standards, goodwill and certain other indefinite-lived intangible assets that are not subject to amortization are reviewed annually or more frequently for impairment, if certain conditions exist, and may be impaired. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings, which could cause a material adverse impact on our reported results of operations and financial position.

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

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

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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 offer. 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.

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CAPITALIZATION

The following table summarizes our cash position and capitalization as of September 30, 2010 as reported and as adjusted, with the latter reflecting the November 2010 debt exchange transaction described in “Propsectus Summary — Recent Developments” and October 2010 debt issuance, exchange and repurchase transactions described in Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010. This table should be read in conjunction with the information included under the headings “Use of Proceeds,” “Selected Historical Consolidated Financial Data for EFH Corp. and Its Subsidiaries,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010” and our consolidated financial statements and related notes included elsewhere in this prospectus.

	As of September 30, 2010
	As Reported			As Adjusted
Cash and cash equivalents (a)		652			614
Debt:
EFH Corp.:
5.550% Series P Senior Notes due 2014 (b)		434			434
6.500% Series Q Senior Notes due 2024 (b)		740			740
6.550% Series R Senior Notes due 2034 (b)		744			744
10.875% Senior Notes due 2017 (c)		359			359
11.250/12.000% Senior Toggle Notes due 2017 (c)		539			539
9.75% Senior Secured Notes due 2019		115			115
10.000% Senior Secured Notes due 2020		1,061			1,061
Capital lease obligations		5			5
Unamortized fair value discount		(485	)		(485	)
Total EFH Corp. debt		3,512			3,512
EFIH: (d)
9.75% Senior Secured Notes due 2019		141			141
10.000% Senior Secured Notes due 2020		2,180			2,180
Total EFIH debt		2,321			2,321
EFCH: (e)
Secured debt		98			98
Unsecured debt		9			9
Unamortized fair value discount		(10	)		(10	)
Total EFCH debt		97			97
TCEH:
Senior Secured Credit Facilities (f)		21,310			21,310
10.25% Senior Notes due 2015 (including Series B) (f)		4,663			3,164
10.50/11.25% Senior Toggle Notes due 2016 (f)		1,992			1,308
15% Senior Secured Second Lien Notes due 2021 (including Series B)		—			1,571
Other secured debt (g)		350			350
Other unsecured debt		1,540			1,540
Unamortized fair value discount		(139	)		(139	)
Total TCEH debt		29,716			29,104
Debt of other subsidiaries:
Secured debt (h)		83			83
Total consolidated debt		35,729			35,117
EFH Corp. shareholders’ equity		(6,139	)		(5,721	)
Noncontrolling interest in subsidiaries		71			71
Total capitalization	$	29,661		$	29,467

(a) The as adjusted amount reflects cash paid to acquire debt in October 2010, including accrued interest paid. Proceeds from the October 2010 issuance of the TCEH Senior Secured Second Lien Notes were used to repurchase TCEH Senior Notes except for $53 million being held in escrow pending use for payment or repurchase of certain TCEH debt, which is accounted for as restricted cash and thus excluded.

(b) Amounts exclude an aggregate $18 million of the Legacy Notes that are held by EFIH and eliminated in consolidation.

45

(c) Amounts exclude $1.428 billion and $2.166 billion of EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes, respectively, that are held by EFIH and eliminated in consolidation.

(d) Excludes the push down effects of EFIH’s guarantees of the notes, the EFH Corp. Senior Notes and the EFH Corp. Senior Secured Notes.

(e) Excludes the push down effects of EFCH’s guarantees of the notes, the EFH Corp. Senior Notes and the EFH Corp. Senior Secured Notes.

(f) As reported amounts exclude $20 million, $337 million and $70 million of the TCEH Senior Secured Facilities, TCEH 10.25% Notes and TCEH Toggle Notes, respectively, that are held either by EFH Corp. or EFIH and eliminated in consolidation. As adjusted amounts exclude an additional $9 million of TCEH Toggle Notes repurchased and held by EFH Corp. and for the TCEH 10.25% Notes and TCEH Toggle Notes reflect the TCEH exchange and repurchases with proceeds from the issuance of the TCEH Senior Secured Second Lien Notes.

(g) Includes $228 million of funding under the accounts receivable securitization program.

(h) Consists of a building financing lease.

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA FOR

EFH CORP. AND ITS SUBSIDIARIES

The following table sets forth our selected historical consolidated financial data as of and for the periods indicated. The selected historical financial data as of December 31, 2009 and 2008 (Successor) and for the years ended December 31, 2009 and 2008 (Successor), the period from October 11, 2007 through December 31, 2007 (Successor), the period from January 1, 2007 through October 10, 2007 (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, 2007 (Successor), 2006 (Predecessor) and 2005 (Predecessor) and for the years ended December 31, 2006 and 2005 (Predecessor) have been derived from our audited historical consolidated financial statements that are not included in this prospectus. The “Predecessor” period reflects the period prior to the Merger, which occurred on October 10, 2007. The historical financial data as of September 30, 2010 and for the nine months ended September 30, 2010 and 2009 have been derived from our unaudited historical interim condensed consolidated financial statements and related notes included elsewhere in this prospectus. In EFH Corp.’s opinion, such unaudited interim financial data reflects all adjustments, consisting of normal recurring accruals, 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 selected historical consolidated financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Year Ended December 31, 2009” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010,” and our historical consolidated financial statements and related notes that are included elsewhere in this prospectus.

	Successor									Predecessor
	Year Ended December 31,						Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31,
	2009			2008									2006			2005
	(millions of dollars, except ratios)
Operating Revenues	$	9,546		$	11,364		$	1,994		$	8,044		$	10,703		$	10,826
Income (loss) from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles		408			(9,998	)		(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	)
Preference stock dividends		—			—			—			—			—			10
Net income (loss)		408			(9,998	)		(1,360	)		723			2,552			1,712
Net income (loss) attributable to noncontrolling interests		(64	)		160			—			—			—			—
Net income (loss) attributable to EFH Corp.		344			(9,838	)		(1,360	)		723			2,552			1,712
Ratio of earnings to fixed charges (a)		1.24			—			—			2.30			5.11			3.80
Ratio of earnings to combined fixed charges and preference dividends (a)		1.24			—			—			2.30			5.11			3.74
Embedded interest cost on long-term debt — end of period (b)		7.2	%		9.2	%		9.5	%		6.5	%		6.6	%		6.3	%
Capital expenditures, including nuclear fuel	$	2,545		$	3,015		$	716		$	2,542		$	2,337		$	1,148

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	Successor									Predecessor
	December 31,									December 31,
	2009			2008			2007			2006			2005
	(millions of dollars, except ratios)
Total assets — end of year	$	59,662		$	59,263		$	64,804		$	27,216		$	27,978
Property, plant & equipment — net — end of year	$	30,108		$	29,522		$	28,650		$	18,569		$	17,006
Goodwill and intangible assets — end of year	$	17,192		$	17,379		$	27,319		$	729		$	728
Capitalization — end of year
Equity-linked debt securities	$	—		$	—		$	—		$	—		$	179
All other long-term debt, less amounts due currently		41,440			40,838			38,603			10,631			11,153
Preferred stock of subsidiaries (not subject to mandatory redemption) (c)		—			—			—			—			—
EFH Corp. common stock equity		(3,247	)		(3,673	)		6,685			2,140			475
Noncontrolling interests in subsidiaries		1,411			1,355			—			—			—
Total	$	39,604		$	38,520		$	45,288		$	12,771		$	11,807
Capitalization ratios — end of year
Equity-linked debt securities		—	%		—	%		—	%		—	%		1.5	%
All other long-term debt, less amounts due currently		104.6			106.0			85.2			83.2			94.5
Preferred stock of subsidiaries (c)		—			—			—			—			—
EFH Corp. common stock equity		(8.2	)		(9.5	)		14.8			16.8			4.0
Noncontrolling interests in subsidiaries		3.6			3.5			—			—			—
Total		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
Short-term borrowings — end of year	$	1,569		$	1,237		$	1,718		$	1,491		$	798
Long-term debt due currently — end of year	$	417		$	385		$	513		$	485		$	1,250

(a) Fixed charges exceeded “earnings” (net loss) by $10.469 billion and $2.034 billion for the year ended December 31, 2008 and for the period from October 11, 2007 through December 31, 2007, respectively.

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

(c) Preferred stock outstanding at the end of 2008, 2007, 2006 and 2005 has a stated amount of $51 thousand. There was no outstanding preferred stock at the end of 2009.

Note: Although EFH Corp. continued as the same legal entity after the Merger, its “Selected Historical Consolidated Financial Data” for periods preceding the Merger and for periods succeeding the Merger are presented as the consolidated financial statements of the “Predecessor” and the “Successor,” respectively. See “Basis of Presentation” in Note 1 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009. The consolidated financial statements of the Successor reflect the application of “purchase accounting.” Results for 2008 were significantly impacted by impairment charges related to goodwill, trade name and emission allowances intangible assets and natural gas-fueled generation facilities. Results for 2010 reflect the prospective adoption of amended guidance regarding consolidation accounting standards related to variable interest entities that resulted in the deconsolidation of Oncor Holdings as discussed in Note 3 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 included elsewhere in this prospectus and amended guidance regarding transfers of financial assets that resulted in the accounts receivable securitization program no longer being accounted for as a sale of accounts receivable and the funding under the program now reported as short-term borrowings as discussed in Note 5 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 included elsewhere in this prospectus. Results for 2010 were significantly impacted by a goodwill impairment charge as discussed in Note 4 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010.

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	Successor
	Nine Months Ended September 30, 2010			Nine Months Ended September 30, 2009
	(millions of dollars, except ratios)
Operating revenues	$	6,599		$	7,366
Net income (loss)	$	(2,973	)	$	261
Net income attributable to noncontrolling interests	$	—		$	(54	)
Net income (loss) attributable to EFH Corp.	$	(2,973	)	$	207
Ratio of earnings to fixed charges (a)		—			1.21
Ratio of earnings to combined fixed charges and preference dividends (a)		—			1.21
Capital expenditures, including nuclear fuel	$	793		$	2,034

	Successor
	September 30, 2010
	(millions of dollars, except ratios)
Total assets	$	47,114
Property, plant & equipment — net	$	20,530
Goodwill and intangible assets	$	8,618
Capitalization
Long-term debt, less amounts due currently	$	35,169
EFH Corp. shareholders’ equity		(6,139	)
Noncontrolling interests in subsidiaries		71
Total	$	29,101
Capitalization ratios
Long-term debt, less amounts due currently		120.9	%
EFH Corp. shareholders’ equity		(21.1	)
Noncontrolling interests in subsidiaries		0.2
Total		100	%
Short-term borrowings	$	308
Long-term debt due currently	$	252
Embedded interest cost on long-term debt — end of period (b)		8.6	%

(a) Fixed charges exceeded earnings by $2.736 billion for the nine months ended September 30, 2010.

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

Quarterly Information (unaudited)

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

	Successor
	First Quarter		Second Quarter			Third Quarter (a)
2010:
Operating revenues	$	1,999	$	1,993			2,607
Net income (loss)		355		(426	)		(2,902	)
Net income (loss) attributable to EFH Corp.	$	355	$	(426	)		(2,902	)

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	Successor
	First Quarter (b)			Second Quarter			Third Quarter			Fourth Quarter
2009:
Operating revenues	$	2,139		$	2,342		$	2,885		$	2,180
Net income (loss)		454			(139	)		(54	)		147
Net loss attributable to noncontrolling interests		(12	)		(16	)		(26	)		(10	)
Net income (loss) attributable to EFH Corp.	$	442		$	(155	)	$	(80	)	$	137
	Successor
	First Quarter			Second Quarter			Third Quarter (c)			Fourth Quarter (d)
2008:
Operating revenues	$	2,354		$	2,951		$	3,695		$	2,364
Net income (loss)		(1,269	)		(3,331	)		3,617			(9,015	)
Net loss attributable to noncontrolling interests		—			—			—			160
Net income (loss) attributable to EFH Corp.	$	(1,269	)	$	(3,331	)	$	3,617		$	(8,855	)

(a) Net income (loss) amounts include the effects of impairment charge related to goodwill (see Note 4 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 included elsewhere in this prospectus).

(b) Net income (loss) amounts include the effects of impairment charge related to goodwill (see Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 included elsewhere in this prospectus).

(c) Net income (loss) amounts include the effects of impairment charge related to emission allowances intangible assets (see Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 included elsewhere in this prospectus).

(d) Net income (loss) amounts include the effects of impairment charges related to goodwill, trade name and emission allowances intangible assets and natural gas-fueled generation facilities (see Notes 3 and 5 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 included elsewhere in this prospectus).

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS AS OF AND

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2010

The following discussion and analysis of our financial condition and results of operations covers the three and nine months ended September 30, 2010 and 2009, and was included in EFH Corp.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 filed with the SEC on October 29, 2010 (the “3^rd Quarter MD&A”). You should read the 3^rd Quarter MD&A in conjunction with the “Selected Historical Consolidated Financial Data for EFH Corp. and Its Subsidiaries” and EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 and the notes to those statements, each included elsewhere in this prospectus. The 3^rd Quarter MD&A should also be read in conjunction with the disclosure set forth in “Prospectus Summary — Recent Developments,” which provides material updates to certain of the information contained in the 3^rd Quarter MD&A, as well as with “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Year Ended December 31, 2009” and EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 and the notes to those statements, each included elsewhere in this prospectus. The 3^rd Quarter MD&A 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 3^rd Quarter MD&A in conjunction with “Our Businesses” 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 the 3^rd Quarter MD&A refer to Energy Future Holdings Corp. and/or its subsidiaries, depending on context. See “Glossary” for other defined terms used in the 3^rd Quarter MD&A. All dollar amounts in the tables in the 3^rd Quarter MD&A are stated in millions of U.S. dollars unless otherwise stated.

BUSINESS

We are a Dallas-based holding company with operations consisting principally of our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority-owned (approximately 80%) subsidiary engaged in regulated electricity transmission and distribution operations in Texas. Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. See Notes 1 and 3 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for a description of the material features of these “ring-fencing” measures and for a discussion of the deconsolidation of Oncor (and its majority owner, Oncor Holdings) in 2010 as the result of a change in accounting principles.

Operating Segments

We have aligned and report our business activities as two operating segments: the Competitive Electric segment and the Regulated Delivery segment. The Competitive Electric segment is principally comprised of TCEH. The Regulated Delivery segment is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary. See Notes 1 and 3 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for discussion of the deconsolidation of Oncor Holdings and, accordingly, Oncor and the Regulated Delivery segment, in 2010.

See Note 15 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for further information regarding reportable business segments.

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Significant Activities and Events

Natural Gas Prices and Long-Term Hedging Program — TCEH 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, the company has entered into market transactions involving natural gas-related financial instruments, and as of September 30, 2010, has effectively sold forward approximately 1.25 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 156,000 GWh at an assumed 8.0 market heat rate) for the period from October 1, 2010 through December 31, 2014 at weighted average annual hedge prices ranging from $7.82 per MMBtu to $7.19 per MMBtu.

These transactions, as well as forward power sales, have effectively hedged an estimated 64% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning October 1, 2010 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which is expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.

The long-term hedging program is comprised primarily of contracts with prices based on the New York Mercantile Exchange (NYMEX) Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. The company has hedged more than 95% of the Houston Ship Channel versus Henry Hub pricing point risk for the fourth quarter 2010 and more than 80% for 2011.

The company has entered into related put and call transactions (referred to as collars), primarily for year 2014 of the program, that effectively hedge natural gas prices within a range. These transactions represented 9% of the positions in the long-term hedging program as of September 30, 2010, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. The company expects to use financial instruments, including collars, in future hedging activity under the long-term hedging program.

The following table summarizes the natural gas hedges in the long-term hedging program as of September 30, 2010:

Measure

Balance 2010 (a)

2011

2012

2013

2014

Total

Natural gas hedge volumes (b)

mm MMBtu

~84

~315

~454

~285

~112

~1,250

Weighted average hedge price (c)

$/MMBtu

~7.82

~7.56

~7.36

~7.19

~7.80

—

Weighted average market price (d)

$/MMBtu

~3.94

~4.44

~5.07

~5.29

~5.42

—

(a) Balance of 2010 is from October 1, 2010 through December 31, 2010.

(b) Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity (i.e., delta position) of the derivatives. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 113 million MMBtu in 2014.

(c) Weighted average hedge prices are based on NYMEX Henry Hub prices of forward natural gas sales positions in the long-term hedging program (excluding the impact of offsetting purchases for rebalancing and pricing point basis transactions). Where collars are reflected, sales price represents the collar floor price.

(d) Based on NYMEX Henry Hub prices.

Changes in the fair value of the instruments in the long-term hedging program are being recorded as unrealized gains and losses in net gain from commodity hedging and trading activities in the statement of income, which has and could continue to result in significant volatility in reported net income. Based on the size of the long-term hedging program as of September 30, 2010, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $1.25 billion in pretax unrealized mark-to-market gains or losses.

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Unrealized mark-to-market net gains related to the long-term hedging program are as follows:

	Period Ended September 30, 2010
	Three Months			Nine Months
Effect of natural gas market price changes on open positions	$	934		$	2,353
Reversals of previously recorded amounts on positions settled		(263	)		(792	)
Total unrealized effect (pre-tax)	$	671		$	1,561

The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $3.539 billion and $1.978 billion as of September 30, 2010 and December 31, 2009, respectively. See discussion below under “Operating Results” for realized net gains from hedging activities, which amounts are largely related to the long-term hedging program.

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

The significant cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program reflects declining forward market natural gas prices. As previously disclosed, forward natural gas prices have generally trended downward since mid-2008 as shown in the table of forward NYMEX Henry Hub natural gas prices below. While the long-term hedging program is designed to mitigate the effect on earnings of low wholesale power prices, due to low natural gas prices, these market conditions are challenging to the long-term profitability of our generation assets. Specifically, these lower natural gas prices and the correlated effect in ERCOT on power prices could have a material adverse impact on the overall profitability of our generation assets for periods in which we do not have significant hedge positions. A continuation or worsening of these market conditions would limit our ability to hedge our wholesale power revenues at sufficient price levels to support our interest payments and debt maturities and could adversely impact our ability to refinance our substantial debt due in 2014.

Also see discussion in Note 4 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 regarding the goodwill impairment charge recorded in the three months ended September 30, 2010.

	Forward Market Prices for Calendar Year ($/MMBtu) (a)
Date	2010 (b)		2011		2012		2013		2014
June 30, 2008	$	11.24	$	10.78	$	10.74	$	10.90	$	11.12
September 30, 2008	$	8.58	$	8.54	$	8.41	$	8.30	$	8.30
December 31, 2008	$	7.13	$	7.31	$	7.23	$	7.15	$	7.15
March 31, 2009	$	5.93	$	6.67	$	6.96	$	7.11	$	7.18
June 30, 2009	$	6.06	$	6.89	$	7.16	$	7.30	$	7.43
September 30, 2009	$	6.21	$	6.87	$	7.00	$	7.06	$	7.17
December 31, 2009	$	5.79	$	6.34	$	6.53	$	6.67	$	6.84
March 31, 2010	$	4.27	$	5.34	$	5.79	$	6.07	$	6.36
June 30, 2010	$	4.82	$	5.34	$	5.68	$	5.89	$	6.10
September 30, 2010	$	3.94	$	4.44	$	5.07	$	5.29	$	5.42

(a) Based on NYMEX Henry Hub prices.

(b) For September 30, 2010, June 30, 2010 and March 31, 2010, natural gas prices for 2010 represent the average of forward prices for October through December, July through December and April through December, respectively.

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As of September 30, 2010, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility — see discussion below under “Financial Condition — Liquidity and Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.

The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas and certain other commodity prices and market heat rates on realized pre-tax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH’s unhedged position and forward prices as of September 30, 2010, which for natural gas reflects estimates of electricity generation less amounts hedged through the long-term natural gas hedging program and amounts under existing wholesale and retail sales contracts. On a rolling twelve-month basis, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.

	Balance 2010 (a)		2011		2012		2013		2014
$1.00/MMBtu change in gas price (b)	$	~2	$	~50	$	~80	$	~295	$	~480
0.1/MMBtu/MWh change in market heat rate (c)	$	—	$	~15	$	~38	$	~43	$	~46
$1.00/gallon change in diesel fuel price	$	~1	$	~1	$	~5	$	~46	$	~40

(a) Balance of 2010 is from November 1, 2010 through December 31, 2010.

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

(c) Based on Houston Ship Channel natural gas prices as of September 30, 2010.

Liability Management Program — As of September 30, 2010, EFH Corp. and its subsidiaries (excluding Oncor and its subsidiaries) had $36 billion aggregate principal amount of debt outstanding. Of that amount, $22 billion matures in 2014 and the majority of the remaining amount matures from 2015 to 2017. As a result, in October 2009, we implemented a liability management program focused on improving our balance sheet by reducing debt and extending debt maturities.

Year-to-date October 28, 2010, we acquired $5.635 billion aggregate principal amount of EFH Corp. and TCEH outstanding debt. As consideration for this acquired debt, EFH Corp. issued $561 million aggregate principal amount of EFH Corp. 10% Notes and paid $252 million in cash (excluding accrued interest payments), EFIH issued $2.180 billion aggregate principal amount of EFIH 10% Notes and paid $500 million in cash (excluding accrued interest payments), and TCEH issued $336 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes and paid $290 million in cash (excluding accrued interest payments).

The following table details our liability management program from its inception in October 2009 through October 2010 (debt amounts are principal amounts):

Security	Debt Acquired		Debt Issued/Cash Paid
EFH Corp 10.875% Notes due 2017	$	1,641	$	—
EFH Corp. Toggle Notes due 2017		2,432		—
EFH Corp. 5.55% Series P Senior Notes due 2014		566		—
EFH Corp. 6.50% Series Q Senior Notes due 2024		10		—
EFH Corp. 6.55% Series R Senior Notes due 2034		6		—
TCEH 10.25% Notes due 2015		986		—
TCEH Toggle Notes due 2016		331		—
Term Loans under the TCEH Senior Secured Facilities due 2014		20		—
EFH Corp. and EFIH 9.75% Notes due 2019		—		256
EFH Corp 10% Notes due 2020		—		561
EFIH 10% Notes due 2020		—		2,180
TCEH 15% Notes due 2021		—		336
Cash (a)		—		1,042
Total	$	5,992	$	4,375

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(a) Funded partially by a portion ($95 million) of the proceeds from the $500 million principal amount of EFH Corp. 10% Notes issued in January 2010 and a portion ($290 million) of the proceeds from the $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes issued in October 2010.

The transactions resulted in the capture of $1.617 billion of debt discount and aggregate projected interest savings (pre-tax) through 2014 of approximately $1.1 billion.

See Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for further discussion of the transactions completed under its liability management program.

TCEH Interest Rate Swap Transactions— As of September 30, 2010, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $16.30 billion principal amount of its senior secured debt maturing from 2010 to 2014. All of these swaps were entered into prior to January 1, 2010. Taking into consideration these swap transactions, 11% of our total long-term debt portfolio as of September 30, 2010 was exposed to variable interest rate risk. TCEH also entered into interest rate basis swap transactions, which further reduce the fixed (through swaps) borrowing costs, related to an aggregate of $16.30 billion principal amount of senior secured debt, including swaps entered into in 2010 related to $2.55 billion principal amount of debt and reflecting the expiration in 2010 of swaps related to an aggregate $2.50 billion principal amount of debt. All of these swaps were entered into prior to July 2010. We may enter into additional interest rate hedges from time to time.

Unrealized mark-to-market net losses related to all TCEH interest rate swaps, which are reported in interest expense and related charges, totaled $181 million and $542 million for the three and nine months ended September 30, 2010, respectively. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.755 billion and $1.212 billion as of September 30, 2010 and December 31, 2009, respectively, of which $120 million and $194 million (both pre-tax), respectively, was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. See discussion in Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 regarding various interest rate swap transactions.

Texas Generation Facilities Development —TCEH has substantially completed a program to develop three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in Texas with a total estimated capacity of approximately 2,200 MW. The Sandow and first Oak Grove units achieved substantial completion (as defined in the EPC agreements) in the fourth quarter 2009, and the second Oak Grove unit achieved substantial completion in the second quarter 2010. We began depreciating the units and recognizing revenues and fuel costs for accounting purposes in those respective periods. Aggregate cash capital expenditures for these three units are expected to total approximately $3.25 billion including all construction, site preparation and mining development costs, of which $3.23 billion was spent as of September 30, 2010. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $4.8 billion, and the balance was $4.7 billion as of September 30, 2010. See discussion in Note 7 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 regarding contingencies related to these units.

Idling of Natural Gas-Fueled Units— In September 2010, after receiving affirmation from ERCOT in April 2010, we mothballed (idled) four of our natural gas-fueled units, totaling 1,856 MW of capacity (1,933 MW installed nameplate capacity). As discussed in the 2009 Form 10-K, in 2009 we retired 10 units, totaling 2,114 MW of capacity (2,226 MW installed nameplate capacity), mothballed three units, totaling 1,081 MW capacity (1,135 MW installed nameplate capacity) and entered into RMR (operational standby) agreements with ERCOT for two units, totaling 630 MW capacity (655 MW installed nameplate capacity).

In September 2010, we notified ERCOT of plans to retire eight currently mothballed natural gas-fueled units, totaling 2,633 MW of capacity (2,771 MW installed nameplate capacity) on December 31, 2010. No impairment is expected to be recorded as a result of the planned retirements. ERCOT may affirm the retirements or request RMR agreements for them.

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As of September 30, 2010, TCEH’s operational fleet of natural gas-fueled generation facilities is generally used as peaking resources and consists of 16 units, totaling 2,848 MW installed nameplate capacity, including two units under RMR agreements and excluding eight units operated for unaffiliated parties and 11 mothballed units.

Financial Services Reform Legislation — In July 2010, the U.S. Congress enacted, and President Obama signed, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Financial Reform Act). The primary purposes of the Financial Reform Act are, among other things, to address systemic risk in the financial system; to establish a Bureau of Consumer Financial Protection with broad powers to enforce consumer protection laws and promulgate rules against unfair, deceptive or abusive practices; to enhance regulation of the derivatives markets, including the requirement for central clearing of over-the-counter derivative instruments and additional capital and margin requirements for certain derivative market participants; and to implement a number of new corporate governance requirements for companies with listed or, in some cases, publicly-traded securities. While the legislation is broad and detailed, substantial portions of the legislation will require rulemaking by federal governmental agencies to either implement the standards set out in the legislation or to adopt new standards. As a result, the full scope and effect of the legislation will likely not be known for several years.

Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives market. The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that we use to hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However, end-users that are non-financial entities using the swap to hedge or mitigate commercial risk are exempt from these clearing requirements. The type of asset-backed OTC derivatives that we use to hedge commodity and interest rate risk should be exempt from the clearing requirements. In addition, existing swaps are grandfathered from the clearing requirements.

The Financial Reform Act also requires the posting of cash collateral for uncleared swaps. Because these cash collateral requirements are unclear as to whether an end-user or its counterparty (i.e., swap dealer) is required to post cash collateral, there is a risk that the cash collateral requirement could be used to effectively negate the end-user clearing exemption. However, the legislative history of the Financial Reform Act suggests that it was not Congress’ intent to require end-users (rather that such requirement applies to swap dealers) to post cash collateral with respect to swaps. If we were required to post cash collateral on our swap transactions, our liquidity would likely be materially impacted, and our ability to enter into OTC derivatives to hedge our commodity and interest rate risks would be significantly limited.

We cannot predict the outcome of the rulemakings to implement the OTC derivative market provisions of the Financial Reform Act. These rulemakings could negatively affect our ability to hedge our commodity and interest rate risks. The inability to hedge these risks would likely have a material adverse effect on our results of operations, financial condition or cash flows.

Global Climate Change — Several bills have been introduced in the U.S. Congress or advocated by the Obama Administration that are intended to address climate change using different approaches, including most prominently a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade). These bills include the Waxman-Markey bill, known as the American Clean Energy and Security Act of 2009 (Waxman-Markey), the Kerry-Boxer bill, known as the Clean Energy Jobs and American Power Act (Kerry-Boxer) and the Kerry-Lieberman bill, known as the American Power Act (Kerry-Lieberman). This proposed legislation is not law, but in June 2009 Waxman-Markey was passed by the U.S. House of Representatives and sent to the U.S. Senate for consideration. Kerry-Boxer was reported out of the U.S. Senate Environment and Public Works Committee, but has not been taken up by the Senate as a whole. Kerry-Lieberman was released by its sponsors in May 2010 when it appeared that progress on passing Kerry-Boxer had stalled.

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Recent developments in the U.S. Congress indicate that the prospects for passage of any cap-and-trade legislation in this Congress are not likely. However, if any of them or similar legislation were to be adopted, our costs of compliance could be material.

In December 2009, the EPA issued a finding that GHG emissions endanger human health and the environment and that emissions from motor vehicles contribute to that endangerment. The EPA’s finding required it to begin regulating GHG emissions from motor vehicles and ultimately stationary sources under existing provisions of the federal Clean Air Act. Following its endangerment finding, the EPA took three regulatory actions with respect to the control of GHG emissions. First, in March 2010, the EPA completed a reconsideration of a memorandum issued in December 2008 by then EPA Administrator Stephen Johnson on the issue of when the Clean Air Act’s Prevention of Significant Deterioration (PSD) program would apply to newly identified pollutants such as GHG’s. The EPA determined that the Clean Air Act’s PSD permit requirements would apply when a nation-wide rule requiring the control of a pollutant takes effect. Under this determination, the earliest time that PSD permitting requirements would apply to GHG emissions from stationary sources, including our power generation facilities, would be January 2011 — the first date that new motor vehicles must meet the new GHG standards. Second, in April 2010, the EPA adopted GHG emission standards for certain new motor vehicles. Third, in June 2010, the EPA finalized its so-called “tailoring rule” that established new thresholds of GHG emissions for the applicability of permits under the Clean Air Act for stationary sources, including our power generation facilities. The EPA’s tailoring rule defines the threshold of GHG emissions for determining applicability of the Clean Air Act’s permitting programs and PSD program at levels greater than the lower emission thresholds contained in the Clean Air Act. In addition, in September 2009, the EPA issued a final rule requiring the reporting, by March 2011, of calendar year 2010 GHG emissions from specified large GHG emissions sources in the U.S. (such reporting rule would apply to our lignite-fueled generation facilities).

Recent EPA Actions — The EPA has recently completed several regulatory actions establishing new requirements for control of certain emissions from sources that include coal-fueled generation facilities. It is also currently considering several other regulatory actions, as well as contemplating future additional regulatory actions, in each case that may affect our coal-fueled generation facilities.

Each of our coal-fueled generation facilities is currently equipped with substantial emissions control equipment. All of our coal-fueled generation facilities are equipped with activated carbon injection systems to reduce mercury emissions. Flue gas desulfurization systems designed primarily to reduce sulfur dioxide emissions are installed at Oak Grove Units 1 and 2, Sandow Units 4 and 5, Martin Lake Units 1, 2, and 3, and Monticello Unit 3. Selective catalytic reduction systems designed to reduce nitrogen oxide emissions are installed at Oak Grove Units 1 and 2 and Sandow Unit 4. Selective non-catalytic reduction systems designed to reduce nitrogen oxide emissions are installed at Sandow Unit 5, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Fabric filter systems designed primarily to reduce particulate matter emissions are installed at Oak Grove Units 1 and 2, Sandow Unit 5, Monticello Units 1 and 2, and Big Brown Units 1 and 2. Electrostatic precipitator systems designed primarily to reduce particulate matter emissions are installed at Sandow Unit 4, Martin Lake Units 1, 2, and 3, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Sandow Unit 5 uses a fluidized bed combustion process that facilitates control of nitrogen oxides and sulfur dioxide. Flue gas desulfurization systems, fabric filter systems, and electrostatic precipitator systems also assist in reducing mercury and other emissions.

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

Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions — Following the invalidation of the Clean Air Interstate Rule (CAIR) by the federal courts in July 2008, the EPA was required to revise CAIR to correct the shortcomings identified by the federal courts. In July 2010, the EPA released a proposed rule called the Clean Air Transport Rule (CATR). The CATR, as proposed, would replace CAIR in 2012 and would require no additional emission reductions for Luminant. However, we cannot predict the impact of a final rule on our business, results of operations and financial condition.

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The Clean Air Act requires each state to monitor air quality for compliance with federal health standards. The EPA is required to periodically review, and if appropriate, revise all national ambient quality standards. The standards for ozone are not being achieved in several areas of Texas. The TCEQ adopted State Implementation Plan (SIP) rules in May 2007 to deal with eight-hour ozone standards, which required nitrogen oxide emission reductions from certain of our peaking natural gas-fueled units in the Dallas-Fort Worth area. In March 2008, the EPA made the eight-hour ozone standards more stringent. In January 2010, the EPA proposed to further reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. Since the EPA projects that SIP rules to address attainment of these new more stringent standards will not be required until December 2013, we cannot yet predict the impact of this action on our generation facilities. In January 2010, the EPA added a new one-hour nitrogen oxide National Ambient Air Quality standard that may require actions within Texas to reduce emissions. The TCEQ will be required to revise its monitoring network and submit an implementation plan with compliance required by January 2021/2022. In June 2010, the EPA adopted a new one-hour sulfur dioxide national ambient air quality standard that may require action within Texas to reduce sulfur dioxide emissions. The TCEQ will be required to conduct modeling and develop an implementation plan by 2014, pursuant to which compliance will be required by 2017, according to the EPA’s implementation timeline. We cannot predict the impact of the new standards on our business, results of operations or financial condition until the TCEQ adopts (if required) an implementation plan with respect to the standards. If the TCEQ adopts implementation plans that require us to install additional emissions controls, or if the EPA adopts more stringent requirements through any of the number of potential rulemaking activities in which it is or may be engaged, we could incur material capital expenditures and higher operating costs, resulting in material adverse effects on our financial condition, liquidity and results of operations.

The EPA has also agreed, in a federal court consent decree, to publish proposed regulations concerning emissions of mercury and other hazardous air pollutants from electricity generating units by March 2011, and to finalize those regulations late in 2011. We cannot predict the substance of any final EPA regulations on such hazardous air pollutants. However, the EPA has informally indicated that recently proposed regulations regarding hazardous air pollutants from industrial boilers may serve as a template for the forthcoming electricity generating unit regulations. The industrial boiler regulations, if applied to electricity generating units, would likely require significant additions of control equipment. If required, such additions would result in material costs of compliance for our generation units, including capital expenditures to install new control equipment and higher operating costs, resulting in material adverse effects on our financial condition, liquidity and results of operations.

In October 2010, the EPA proposed to retroactively disapprove a portion of the SIP pursuant to which the state implements its program to achieve the EPA’s National Ambient Air Quality Standards (NAAQS) under the Clean Air Act. In particular, the EPA proposes to retroactively disapprove certain standard permits for pollution control projects that the TCEQ adopted approximately 10 years ago. The EPA asserts that we hold such standard permits for two generation facilities (Big Brown and Stryker Creek). We are investigating the basis for the EPA’s assertion. The EPA has proposed to disapprove this portion of the SIP while acknowledging that emissions covered by these standard permits do not threaten attainment or maintenance of the NAAQS under the Clean Air Act. We believe the TCEQ’s adoption of the standard permit was consistent with the Clean Air Act. However, we cannot predict whether the EPA will take final action to disapprove this portion of the SIP. If the EPA takes final disapproval action, and if that causes us to undertake additional permitting activity and install additional emissions control equipment at our affected generation facilities, we could incur material capital expenditures, resulting in material adverse effects on our financial condition, liquidity and results of operations.

Solid Waste, Including Fly Ash Associated with Lignite/Coal-Fueled Generation — Treatment, storage and disposal of solid and hazardous waste are regulated at the federal and state level. In December 2008, an ash impoundment facility at a Tennessee Valley Authority (TVA) site ruptured, releasing a significant quantity of coal ash slurry. No impoundment failures of this magnitude have ever occurred at any of our impoundments, which are significantly smaller than TVA’s and are inspected on a regular basis. We routinely sample groundwater monitoring wells to ensure compliance with all applicable regulations. As a result of the TVA ash impoundment failure, in May 2010, the EPA released a proposed rule that considers regulating coal combustion residuals as either a hazardous waste or a non-hazardous waste. We are unable to predict the requirements of a final rule; however, the potential cost of compliance could be material.

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

As of September 30, 2010, Oncor has installed approximately 1,343,000 advanced digital meters, including approximately 683,000 during the nine months ended September 30, 2010. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $324 million as of September 30, 2010. Oncor expects to complete installations of all three million meters by the end of 2012.

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

RESULTS OF OPERATIONS

Pro Forma Consolidated Financial Results

As the result of deconsolidation of Oncor Holdings effective 2010, the results of Oncor Holdings are reflected in the 2010 consolidated statement of income as equity in earnings of unconsolidated subsidiary (net of tax) instead of separately as revenues and expenses as they are shown for periods prior to January 1, 2010. The following pro forma results for the three and nine months ended September 30, 2009 are presented to provide for a meaningful comparison, along with the analyses on the following pages, of consolidated operating results in consideration of the deconsolidation of Oncor Holdings as discussed in Notes 1 and 3 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010.

	Three Months Ended September 30, 2010			Three Months Ended September 30, 2009
				As Reported			Pro Forma Adjustments (a)			Pro Forma
	(millions of dollars)
Operating revenues	$	2,607		$	2,885		$	(452	)	$	2,433
Fuel, purchased power costs and delivery fees		(1,400	)		(870	)		(317	)		(1,187	)
Net gain from commodity hedging and trading activities		992			123			—			123
Operating costs		(197	)		(388	)		228			(160	)
Depreciation and amortization		(352	)		(456	)		147			(309	)
Selling, general and administrative expenses		(187	)		(277	)		50			(227	)
Franchise and revenue-based taxes		(24	)		(94	)		67			(27	)
Impairment of goodwill		(4,100	)		—			—			—
Other income		1,033			45			(10	)		35
Other deductions		(4	)		(32	)		28			(4	)
Interest income		—			18			(3	)		15
Interest expense and related charges		(1,018	)		(1,039	)		75			(964	)
Loss before income taxes and equity in earnings of unconsolidated subsidiaries		(2,650	)		(85	)		(187	)		(272	)
Income tax (expense) benefit		(370	)		31			56			87
Equity in earnings of unconsolidated subsidiaries (net of tax)		118			—			105			105
Net loss		(2,902	)		(54	)		(26	)		(80	)
Net income attributable to noncontrolling interests		—			(26	)		26			—
Net loss attributable to EFH Corp.	$	(2,902	)	$	(80	)	$	—		$	(80	)

(a) All pro forma adjustments relate to Oncor Holdings and result in the presentation of the investment in Oncor Holdings under the equity method of accounting for the three months ended September 30, 2009.

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	Nine Months Ended September  30, 2010			Nine Months Ended September 30, 2009
				As Reported			Pro Forma Adjustments (a)			Pro Forma
	(millions of dollars)
Operating revenues	$	6,599		$	7,366		$	(1,219	)	$	6,147
Fuel, purchased power costs and delivery fees		(3,521	)		(2,171	)		(816	)		(2,987	)
Net gain from commodity hedging and trading activities		2,272			1,003			—			1,003
Operating costs		(623	)		(1,171	)		668			(503	)
Depreciation and amortization		(1,043	)		(1,286	)		405			(881	)
Selling, general and administrative expenses		(560	)		(792	)		138			(654	)
Franchise and revenue-based taxes		(73	)		(259	)		185			(74	)
Impairment of goodwill		(4,100	)		(90	)		—			(90	)
Other income		1,278			71			(30	)		41
Other deductions		(23	)		(50	)		32			(18	)
Interest income		9			30			—			30
Interest expense and related charges		(3,092	)		(2,136	)		225			(1,911	)
Income (loss) before income taxes and equity in earnings of unconsolidated subsidiaries		(2,877	)		515			(412	)		103
Income tax expense		(336	)		(254	)		141			(113	)
Equity in earnings of unconsolidated subsidiaries (net of tax)		240			—			217			217
Net income (loss)		(2,973	)		261			(54	)		207
Net income attributable to noncontrolling interests		—			(54	)		54			—
Net income (loss) attributable to EFH Corp.	$	(2,973	)	$	207		$	—		$	207

(a) All pro forma adjustments relate to Oncor Holdings and result in the presentation of the investment in Oncor Holdings under the equity method of accounting for the nine months ended September 30, 2009.

Consolidated Financial Results — Three Months Ended September 30, 2010 Compared to Pro Forma Three Months Ended September 30, 2009

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

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SG&A expenses decreased $40 million, or 18%, to $187 million in 2010. The decline reflected decreases in both the Competitive Electric segment and Corporate and Other and was driven by $13 million in lower bad debt expense, $11 million in lower transition costs associated with outsourced support services, $5 million in lower marketing expenses and $3 million in lower employee compensation-related expense.

See Note 4 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for discussion of the $4.1 billion impairment of goodwill recorded in the Competitive Electric segment in 2010.

Other income totaled $1.033 billion in 2010 and $35 million in 2009. The 2010 amount included debt extinguishment gains totaling $1.023 billion (see discussion of debt exchanges and repurchases in Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010). The 2009 amount included $23 million arising from the reversal of a use tax accrual recorded in purchase accounting related to periods prior to the Merger, which was triggered by a state ruling in the third quarter 2009. See Note 16 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for details of other income and deductions.

Interest income totaled $15 million in 2009 primarily representing interest on $465 million in collateral under a funding arrangement described in Note 11 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010.

Interest expense and related charges increased $54 million to $1.018 billion in 2010 reflecting $43 million in higher unrealized mark-to-market net losses related to interest rate swaps and a $73 million decrease in capitalized interest due to completion of certain new generation facility construction activities, partially offset by a $37 million decrease in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges, reflecting values attributed to earlier periods, as well as lower interest expense resulting from reduced debt under the liability management program as described above under “Significant Activities and Events.” Also see Note 16 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010.

Income tax expense totaled $370 million in 2010 compared to an income tax benefit of $87 million in 2009. The effective tax rate was 25.5% and 32.0% in 2010 and 2009, respectively, excluding the effect of the $4.1 billion nondeductible goodwill impairment charge in 2010. The decrease in the rate was driven by a $146 million reversal of previously accrued interest related to uncertain income tax positions due to the expected resolution of matters related to the 1997-2002 tax audit (See Note 16 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010).

Equity in earnings of unconsolidated subsidiaries (net of tax) totaled $118 million in 2010 compared to $105 million in 2009 reflecting a $17 million increase (which is before the effect of noncontrolling interests) in Oncor’s net income. The increase was driven by higher revenues, primarily due to rate increases and weather, and the effect of a $25 million write off of regulatory assets in 2009, partially offset by increased noncash expenses recognized as a result of the rate case.

Net loss attributable to EFH Corp. increased $2.822 billion to $2.902 billion in 2010.

• Net loss in the Competitive Electric segment increased $3.666 billion to $3.710 billion.

• Earnings from the Regulated Delivery segment increased $13 million to $118 million as discussed above.

• Corporate and Other net income totaled $690 million in 2010 compared to net expenses of $141 million in 2009. The amounts in 2010 and 2009 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The $831 million change reflected debt extinguishment gains in 2010 totaling $659 million, the $121 million Corporate and Other portion of the 2010 reversal of previously accrued interest on uncertain tax positions discussed above, $20 million in lower SG&A expense primarily reflecting lower transition costs associated with outsourced support services and costs allocated to the competitive operations effective 2010 and $7 million decrease in interest expense driven by lower borrowings (all amounts after-tax).

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Consolidated Financial Results — Nine Months Ended September 30, 2010 Compared to Pro Forma Nine Months Ended September 30, 2009

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

SG&A expenses decreased $94 million, or 14%, to $560 million in 2010 driven by $57 million in lower transition costs associated with outsourced support services and the retail customer information system implemented in 2009, $13 million in lower employee compensation-related expense, and $9 million of accounts receivable securitization program fees that are reported as interest expense and related charges in 2010 (see Note 5 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010).

See Note 4 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for discussion of the $4.1 billion impairment of goodwill recorded in the Competitive Electric segment in 2010. The $90 million impairment of goodwill recorded in 2009 largely related to the Competitive Electric segment and resulted from the completion of fair value calculations supporting a goodwill impairment charge recorded in the fourth quarter of 2008 as discussed in Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

Other income totaled $1.278 billion in 2010 and $41 million in 2009. The 2010 amount included debt extinguishment gains totaling $1.166 billion (see discussion of debt exchanges and repurchases in Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010), a $44 million gain on sale of land and related water rights and a $37 million gain on sale of interests in a natural gas gathering pipeline business. The 2009 amount included $23 million arising from the reversal of a use tax accrual recorded in purchase accounting related to periods prior to the Merger, which was triggered by a state ruling in the third quarter 2009. See Note 16 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for details of other income and deductions.

Interest income decreased $21 million, or 70%, to $9 million in 2010 reflecting lower interest in 2010 on $465 million in collateral under a funding arrangement, due to settlement of the arrangement as described in Note 11 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010.

Interest expense and related charges increased $1.181 billion to $3.092 billion in 2010 reflecting a $542 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $527 million net gain in 2009 and a $200 million decrease in capitalized interest due to completion of new generation facility construction activities, partially offset by $68 million in decreased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges, reflecting values attributed to earlier periods, as well as lower interest expense resulting from reduced debt under the liability management program as described above under “Significant Activities and Events.” Also, see Note 16 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010.

Income tax expense totaled $336 million in 2010 compared to $113 million in 2009. Excluding the effects of the $4.1 billion and $90 million nondeductible goodwill impairment charges in 2010 and 2009, respectively, the effective tax rates were 27.5% in 2010 and 58.5% in 2009. The decrease in the effective tax rate in 2010 reflected the $146 million favorable adjustment in the third quarter related to uncertain tax positions (see Note 16 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010) net of the effect of an $8 million deferred tax charge in the first quarter related to the Patient Protection and Affordable Care Act (see Note 13 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010). The effective tax rate in 2009 reflected the effect of interest accruals related to uncertain tax positions on a small income base.

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Equity in earnings of unconsolidated subsidiaries (net of tax) totaled $240 million in 2010 compared to $217 million in 2009 reflecting a $32 million increase (which is before the effect of noncontrolling interests) in Oncor’s net income. The increase was driven by higher revenues, primarily due to rate increases and weather, and the effect of a $25 million write off of regulatory assets in 2009, partially offset by increased noncash expenses recognized as a result of the rate case.

Net earnings attributable to EFH Corp. decreased $3.180 billion to a loss of $2.973 billion in 2010.

• Results in the Competitive Electric segment decreased $4.141 billion to a loss of $3.705 billion.

• Earnings from the Regulated Delivery segment increased $23 million to $240 million as discussed above.

• Corporate and Other net income totaled $492 million in 2010 compared to net expenses of $446 million in 2009. The amounts in 2010 and 2009 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The change of $938 million reflected $758 million in debt extinguishment gains in 2010, the $121 million Corporate and Other portion of the 2010 reversal of accrued interest on uncertain tax positions discussed above, $55 million in lower SG&A expense primarily reflecting lower transition costs associated with outsourced support services and costs allocated to the competitive operations effective 2010 and a $20 million goodwill impairment charge in 2009, partially offset by a $26 million increase in interest expense driven by higher borrowings and an $8 million deferred tax charge due to the implementation of the Patient Protection and Affordable Care Act (all amounts after-tax).

Non-GAAP Earnings Measures

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

Competitive Electric Segment

Financial Results

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Operating revenues	$	2,607		$	2,433		$	6,599		$	6,144
Fuel, purchased power costs and delivery fees		(1,400	)		(1,187	)		(3,521	)		(2,987	)
Net gain from commodity hedging and trading activities		992			123			2,272			1,003
Operating costs		(197	)		(161	)		(623	)		(504	)
Depreciation and amortization		(345	)		(303	)		(1,027	)		(862	)
Selling, general and administrative expenses		(183	)		(192	)		(546	)		(555	)
Franchise and revenue-based taxes		(24	)		(27	)		(72	)		(74	)
Impairment of goodwill		(4,100	)		—			(4,100	)		(70	)
Other income		6			33			95			38
Other deductions		(3	)		(7	)		(14	)		(22	)
Interest income		23			21			65			40
Interest expense and related charges		(883	)		(798	)		(2,604	)		(1,414	)
Income (loss) before income taxes		(3,507	)		(65	)		(3,476	)		737
Income tax (expense) benefit		(203	)		21			(229	)		(301	)
Net income (loss)	$	(3,710	)	$	(44	)	$	(3,705	)	$	436

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Competitive Electric Segment

Sales Volume and Customer Count Data

	Three Months  Ended September 30,						%			Nine Months  Ended September 30,						%
	2010			2009			Change			2010			2009			Change
Sales volumes:
Retail electricity sales volumes — (GWh):
Residential		9,473			9,348			1.3			23,040			22,312			3.3
Small business (a)		2,417			2,598			(7.0	)		6,392			6,228			2.6
Large business and other customers		4,294			4,049			6.1			11,738			10,905			7.6
Total retail electricity		16,184			15,995			1.2			41,170			39,445			4.4
Wholesale electricity sales volumes		14,011			10,126			38.4			37,359			30,180			23.8
Net sales (purchases) of balancing electricity to/from ERCOT		302			(38	)		—			572			(304	)		—
Total sales volumes		30,497			26,083			16.9			79,101			69,321			14.1
Average volume (kWh) per residential customer (b)		5,220			4,936			5.8			12,584			11,772			6.9
Weather (North Texas average) — percent of normal (c):
Cooling degree days		107.1	%		97.1	%		10.3			109.9	%		102.2	%		7.5
Heating degree days		—	%		—	%		—			132.1	%		93.7	%		41.0
Customer counts:
Retail electricity customers (end of period and in thousands) (d):
Residential											1,800			1,876			(4.1	)
Small business (a)											228			273			(16.5	)
Large business and other customers											22			23			(4.3	)
Total retail electricity customers											2,050			2,172			(5.6	)

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

(b) Calculated using average number of customers for the 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). Normal is defined as the average over a 10-year period.

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

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Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities

	Three Months Ended September 30,						%			Nine Months Ended September 30,						%
	2010			2009			Change			2010			2009			Change
Operating revenues:
Retail electricity revenues:
Residential	$	1,231		$	1,272			(3.2	)	$	3,007		$	3,048			(1.3	)
Small business (a)		309			366			(15.6	)		839			924			(9.2	)
Large business and other customers		340			330			3.0			931			955			(2.5	)
Total retail electricity revenues		1,880			1,968			(4.5	)		4,777			4,927			(3.0	)
Wholesale electricity revenues (b)		642			380			68.9			1,612			1,043			54.6
Net sales (purchases) of balancing electricity to/from ERCOT		(6	)		(5	)		(20.0	)		(23	)		(50	)		54.0
Amortization of intangibles (c)		14			20			(30.0	)		16			10			60.0
Other operating revenues		77			70			10.0			217			214			1.4
Total operating revenues	$	2,607		$	2,433			7.2		$	6,599		$	6,144			7.4
Net gain from commodity hedging and trading activities:
Unrealized net gains from changes in fair value	$	979		$	136			—		$	2,255		$	1,026			—
Unrealized net losses representing reversals of previously recognized fair values of positions settled in the current period		(238	)		(116	)		—			(698	)		(257	)		—
Realized net gains on settled positions		251			103			—			715			234			—
Total gain	$	992		$	123			—		$	2,272		$	1,003			—

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

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

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010		2009
Reported in revenues	$	42		$	(11	)	$	10	$	(135	)
Reported in fuel and purchased power costs		(16	)		(6	)		48		79
Net gain (loss)	$	26		$	(17	)	$	58	$	(56	)

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

65

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Three Months Ended September 30,						%			Nine Months Ended September 30,						%
	2010			2009			Change			2010			2009			Change
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	43		$	30	(f)		43.3		$	116		$	88	(f)		31.8
Lignite/coal		246			175			40.6			678			474			43.0
Total baseload fuel		289			205			41.0			794			562			41.3
Natural gas fuel and purchased power (a)		580			431			34.6			1,294			953			35.8
Amortization of intangibles (b)		45			82	(f)		(45.1	)		125			222	(f)		(43.7	)
Other costs		46			39			17.9			152			145			4.8
Fuel and purchased power costs		960			757			26.8			2,365			1,882			25.7
Delivery fees (c)		440			430			2.3			1,156			1,105			4.6
Total	$	1,400		$	1,187			17.9		$	3,521		$	2,987			17.9
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	8.13		$	5.76	(f)		41.1		$	7.84		$	5.67	(f)		38.3
Lignite/coal (d)		18.24			16.53			10.3			19.18			16.49			16.3
Natural gas fuel and purchased power		54.33			47.99			13.2			49.56			44.06			12.5
Delivery fees per MWh	$	27.13		$	26.68			1.7		$	28.01		$	27.77			0.9
Production and purchased power volumes (GWh):
Nuclear		5,302			5,219			1.6			14,841			15,512			(4.3	)
Lignite/coal		15,445			12,209			26.5			40,743			32,914			23.8
Total baseload generation		20,747			17,428			19.0			55,584			48,426			14.8
Natural gas-fueled generation		763			1,135			(32.8	)		1,598			2,168			(26.3	)
Purchased power		9,905			7,890			25.5			24,505			19,523			25.5
Total energy supply		31,415			26,453			18.8			81,687			70,117			16.5
Less line loss and power imbalances (e)		918			370			—			2,586			796			—
Net energy supply volumes		30,497			26,083			16.9			79,101			69,321			14.1
Baseload capacity factors:
Nuclear		104.4	%		103.1	%		1.3			98.5	%		103.1	%		(4.5	)
Lignite/coal		89.7	%		94.0	%		(4.6	)		82.0	%		85.9	%		(4.5	)
Total baseload		93.2	%		96.6	%		(3.5	)		86.0	%		90.7	%		(5.2	)

(a) See note (b) on previous page.

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

(c) Includes delivery fee charges from Oncor.

(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.

(e) Includes physical purchases and sales, the financial results of which are reported in commodity hedging and trading activities in the income statement.

(f) Reflects reclassification to correct amortization.

Competitive Electric Segment — Financial Results — Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

Operating revenues increased $174 million, or 7%, to $2.607 billion in 2010.

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Wholesale electricity revenues increased $262 million, or 69%, to $642 million in 2010. A 38% increase in wholesale electricity sales volumes, primarily reflecting production from the new generation units and increased sales to third-party REPs, increased revenue $150 million. An 11% increase in average wholesale electricity prices, reflecting higher natural gas prices at the time underlying contracts were executed, increased revenues by $59 million. The balance of the revenue increase reflected unrealized gains in 2010 compared to unrealized losses in 2009 related to physical derivative commodity sales contracts as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above.

Bilateral electricity contracting activity includes hedging transactions that utilize contracts for physical delivery. Wholesale sales and purchases of electricity are reported gross in the income statement if the transactions are scheduled for physical delivery with ERCOT.

Comparisons of wholesale balancing activity, reported net, 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.

Retail electricity revenues decreased $88 million, or 4%, to $1.880 billion and reflected the following:

• Lower average pricing decreased revenues by $111 million reflecting declines in both the business and residential markets. Lower average pricing is reflective of competitive activity in a lower wholesale power price environment and a change in business customer mix.

• A 1% increase in sales volumes increased revenues by $23 million. Residential sales volumes increased 1% reflecting greater average consumption driven by hotter weather, partially offset by a 4% decrease in customer count due to competitive activity. Business sales volumes increased 1% reflecting a change in customer mix resulting from contracts executed with new customers.

Fuel, purchased power costs and delivery fees increased $213 million, or 18%, to $1.4 billion in 2010. Higher purchased power costs contributed $131 million to the increase and reflected an increase of 26% in purchased volumes driven by increased unplanned generation unit outages and higher sales to third-party REPs, as well as higher prices driven by higher natural gas prices at the time underlying contracts were executed. Other factors contributing to the increase included $36 million in higher lignite/coal costs at existing plants, driven by higher transportation and commodity costs for purchased coal, $35 million in higher lignite fuel costs related to production from the new generation units, a $13 million increase in nuclear fuel expense reflecting increased prices, a $10 million increase in unrealized losses related to physical derivative commodity purchase contracts, a $10 million increase in delivery costs and a $5 million increase in natural gas costs driven by higher prices. These increases were partially offset by $37 million in lower amortization of the intangible net asset values (including the stepped-up value of nuclear fuel) resulting from purchase accounting and reflected expiration of commodity contracts and consumption of the nuclear fuel.

Overall baseload generation production increased 19% in 2010 driven by the production in 2010 from the new generation units.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities for the three months ended September 30, 2010 and 2009, which totaled $992 million and $123 million, respectively:

Three Months Ended September 30, 2010 —Unrealized mark-to-market net gains totaling $741 million included:

• $750 million in net gains related to hedge positions, which includes $980 million in net gains from changes in fair value driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $230 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

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• $9 million in net losses related to trading positions, which largely represent reversals of previously recorded net gains on positions settled in the period.

Realized net gains totaling $251 million included:

• $235 million in net gains related to positions that primarily hedged electricity revenues recognized in the period largely related to the long-term hedging program, and

• $16 million in net gains related to trading positions.

Three Months Ended September 30, 2009 — Unrealized mark-to-market net gains totaling $20 million included:

• $4 million in net losses related to hedge positions, which includes $121 million in net gains from changes in fair value driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $125 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

• $24 million in net gains related to trading positions, which includes $15 million in net gains from changes in fair value and $9 million in net gains that represent reversals of previously recorded net losses on positions settled in the period.

Realized net gains totaling $103 million included:

• $110 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

• $7 million in net losses related to trading positions.

Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $26 million in net gains in 2010 and $17 million in net losses in 2009.

Operating costs increased $36 million, or 22%, to $197 million in 2010. The increase reflected $26 million related to the new generation units. The balance of the increase reflected various base maintenance activities.

Depreciation and amortization increased $42 million, or 14%, to $345 million in 2010. The increase was driven by depreciation of the new generation units and associated mining operations.

SG&A expenses decreased $9 million, or 5%, to $183 million in 2010. The decrease reflected $13 million in lower bad debt expense reflecting 2009 delinquencies due to delays in final bills and disconnects resulting from a system conversion, $5 million in lower marketing expenses and $3 million in lower employee compensation-related expense, partially offset by $12 million of costs allocated from corporate in 2010, principally fees paid to the Sponsor Group and individually insignificant increases in various other expenses.

See Note 4 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for discussion of the $4.1 billion impairment of goodwill recorded in 2010.

Other income totaled $6 million in 2010 and $33 million in 2009. The 2009 amount included a $23 million reversal of a use tax accrual and a $6 million fee received related to an interest rate swap/commodity hedge derivative agreement. See Note 16 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for additional details.

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Interest expense and related charges increased by $85 million to $883 million in 2010 reflecting a $73 million decrease in capitalized interest due to completion of certain new generation facility construction activities and a $43 million increase in unrealized mark-to-market net losses related to interest rate swaps, partially offset by a $37 million decrease in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges.

Income tax expense totaled $203 million in 2010 compared to a benefit of $21 million in 2009. Excluding the $4.1 billion nondeductible goodwill impairment charge the effective tax rate was 34.2% in 2010, and the effective benefit rate was 32.3% on a loss in 2009. The 2010 effective rate reflected a portion of the reversal of interest accrued on uncertain tax positions discussed above. The 2009 rate was depressed by the interest accrued on such positions, reflecting the loss position.

Loss for the segment increased $3.666 billion to a loss of $3.710 billion in 2010 reflecting the $4.1 billion goodwill impairment charge and increased interest expense, partially offset by an increase in realized and unrealized net gains from commodity hedging and trading activities.

Competitive Electric Segment — Financial Results — Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Operating revenues increased $455 million, or 7%, to $6.599 billion in 2010.

Wholesale electricity revenues increased $569 million, or 55%, to $1.612 billion in 2010. A 24% increase in wholesale electricity sales volumes, reflecting production from the new generation units and increased sales to third-party REPs, increased revenues by $280 million. A 10% increase in average wholesale electricity prices, reflecting higher natural gas prices at the time the underlying contracts were executed, increased revenues by $145 million. The balance of the revenue increase reflected unrealized gains in 2010 compared to unrealized losses in 2009 related to physical derivative commodity sales contracts as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above.

Retail electricity revenues decreased $150 million, or 3%, to $4.777 billion and reflected the following:

• Lower average pricing decreased revenues by $366 million reflecting declines in both the business and residential markets. Lower average pricing is reflective of competitive activity in a lower wholesale power price environment and a change in business customer mix.

• A 4% increase in sales volumes increased revenues by $216 million reflecting increases in both the business and residential markets. A 6% increase in business markets sales volumes reflected a change in customer mix resulting from contracts executed with new customers. Higher average consumption resulted in a 3% overall increase in residential sales volumes, reflecting colder winter weather and hotter summer weather, partially offset by a decline in residential customer counts.

Fuel, purchased power costs and delivery fees increased $534 million, or 18%, to $3.521 billion in 2010. Higher purchased power costs contributed $295 million to the increase and reflected increased volumes driven by increased planned and unplanned generation unit outages and higher retail demand, as well as increased prices driven by the effect of higher natural gas prices at the time the underlying contracts were executed. Other factors contributing to the increase included $105 million in lignite fuel costs related to production from the new generation units, $99 million in higher lignite/coal costs at existing plants, reflecting higher purchased coal transportation and commodity costs, $51 million in higher delivery fees, reflecting increased retail sales volumes and tariffs, a $31 million decrease in unrealized gains related to physical derivative commodity purchase contracts, a $28 million increase in nuclear fuel expense reflecting increased prices and a $12 million increase in natural gas and fuel oil costs driven by higher prices. These increases were partially offset by $97 million in lower amortization of the intangible net asset values (including the stepped-up value of nuclear fuel) resulting from purchase accounting and reflected expiration of commodity contracts and consumption of the nuclear fuel.

69

Overall baseload generation production increased 15% in 2010 reflecting a 24% increase in lignite/coal-fueled production, driven by production from new generation units, partially offset by a 4% decrease in nuclear production reflecting an unplanned transformer outage in January 2010 and year-to-year timing differences of planned outages.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities for the nine months ended September 30, 2010 and 2009, which totaled $2.272 billion and $1.003 billion, respectively:

Nine Months Ended September 30, 2010 — Unrealized mark-to-market net gains totaling $1.557 billion included:

• $1.564 billion in net gains related to hedge positions, which includes $2.232 billion in net gains from changes in fair value driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $668 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

• $7 million in net losses related to trading positions, which includes $23 million in net gains from changes in fair value, and $30 million in net losses that represent reversals of previously recorded net gains on positions settled in the period.

Realized net gains totaling $715 million included:

• $666 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, largely related to the long-term hedging program, and

• $49 million in net gains related to trading positions.

Nine Months Ended September 30, 2009 — Unrealized mark-to-market net gains totaling $769 million included:

• $750 million in net gains related to hedge positions, which includes $1.010 billion in net gains from changes in fair value, driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $260 million in net losses that represent reversals of previously recorded fair values of positions settled in the period, and

• $19 million in net gains related to trading positions, which includes $16 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 gains totaling $234 million include:

• $247 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

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

Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $58 million in net gains in 2010 and $56 million in net losses in 2009.

Operating costs increased $119 million, or 24%, to $623 million in 2010. The increase reflected $71 million in incremental expense related to the new generation units and $26 million in outage-related costs at the Comanche Peak nuclear-fueled plant reflecting year-to-year timing of planned outage maintenance costs and the first quarter 2010 unplanned transformer-related outage. The balance of the increase reflected increased costs related to outages at the legacy lignite/coal operations and various individually insignificant increases.

70

Depreciation and amortization increased $165 million, or 19%, to $1.027 billion in 2010. The increase reflected $129 million in incremental expense related to the new generation units and associated mining operations. The balance of the increase was primarily driven by equipment additions.

SG&A expenses decreased $9 million, or 2%, to $546 million in 2010. The decrease reflected:

• $23 million in lower transition costs associated with outsourced services and the retail customer information management system implemented in 2009;

• $13 million in lower employee compensation-related expense in 2010; and

• $9 million of accounts receivable securitization program fees that are reported in 2010 as interest expense and related charges (see Note 5 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010),

partially offset by:

• $35 million of costs allocated from corporate in 2010, principally fees paid to the Sponsor Group, and

• $4 million in higher marketing expenses in 2010.

See Note 4 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for discussion of the $4.1 billion impairment of goodwill recorded in 2010. The $70 million impairment of goodwill recorded in 2009 resulted from the completion of fair value calculations supporting a goodwill impairment charge recorded in the fourth quarter of 2008 as discussed in Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

Other income totaled $95 million in 2010 and $38 million in 2009. Other income in 2010 included a $44 million gain on the sale of land and related water rights and a $37 million gain associated with the sale of interests in a natural gas gathering pipeline business. The 2009 amount included a $23 million reversal of a use tax accrual. Other deductions totaled $14 million in 2010 and $22 million in 2009 and included a number of individually immaterial expenses. See Note 16 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for additional details.

Interest income increased $25 million, or 63%, to $65 million in 2010 reflecting higher notes receivable balances from affiliates.

Interest expense and related charges increased by $1.190 billion, or 84%, to $2.604 billion in 2010 reflecting a $542 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $527 million net gain in 2009 and a $200 million decrease in capitalized interest due to completion of new generation facility construction activities, partially offset by a $68 million decrease in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges.

Income tax expense totaled $229 million in 2010 compared to $301 million in 2009. Excluding the $4.1 billion and $70 million nondeductible goodwill impairment charges in 2010 and 2009, respectively, the effective tax rates were 36.7% and 37.3%, respectively. The decrease in the rate reflected a portion of the reversal of interest accrued on uncertain tax positions discussed above.

Results for the segment decreased $4.141 billion in 2010 to a loss of $3.705 billion reflecting the $4.1 billion goodwill impairment charge and increased interest expense, partially offset by an increase in net gains from commodity hedging and trading activities.

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

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2010 and 2009. The net change in these assets and liabilities, excluding “other activity” as described below, represents the pretax effect on earnings of positions in the commodity contract portfolio that are marked-to-market in net income (see Note 11 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010). The portfolio consists primarily of economic hedges but also includes trading positions.

	Nine Months Ended September 30,
	2010			2009
Commodity contract net asset at beginning of period	$	1,718		$	430
Settlements of positions (a)		(642	)		(314	)
Changes in fair value (b)		2,255			1,026
Other activity (c)		39			63
Commodity contract net asset at end of period	$	3,370		$	1,205

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

(b) Represents unrealized gains and losses recognized, primarily related to positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”).

(c) These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration, generally related to options purchased/sold and physical natural gas exchange transactions. 2010 amount includes $59 million related to net payment of option premiums and $19 million related to settlement of a power sales agreement, partially offset by $35 million for expired option premiums and $4 million in natural gas provided under physical gas exchange transactions. 2009 amount includes $28 million related to net payment of option premiums, $25 million in natural gas provided under physical gas exchange transactions and $15 million related to settlement of a power sales agreement, partially offset by $5 million for expired option premiums.

Unrealized gains and losses related to commodity contracts are summarized as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Unrealized gains/(losses) related to contracts marked-to-market	$	765	$	3	$	1,613	$	712
Ineffectiveness gains/(losses) related to cash flow hedges (a)		2		—		2		1
Total unrealized gains (losses) related to commodity contracts	$	767	$	3	$	1,615	$	713

(a) Represents the reversal of previously recorded ineffectiveness upon settlement of such dedesignated hedges in 2010.

Following are the components of the net commodity contract asset as of September 30, 2010:

Amount of net asset arising from mark-to-market accounting	$	3,374
Net liability associated with natural gas under physical gas exchange transactions		(4	)
Net commodity contract asset	$	3,370

Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of September 30, 2010, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

	Maturity dates of unrealized commodity contract asset as of  September 30, 2010
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(144	)	$	(39	)	$	(1	)	$	—		$	(184	)
Prices provided by other external sources		1,300			1,875			129			—			3,304
Prices based on models		4			(16	)		384			(118	)		254
Total	$	1,160		$	1,820		$	512		$	(118	)	$	3,374
Percentage of total fair value		34	%		54	%		15	%		(3	)%		100	%

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The “prices actively quoted” category reflects only exchange traded contracts for which active quotes are readily available. The “prices provided by other external sources” category represents forward commodity positions valued using prices for which over-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT that are deemed active markets (excluding the West zone) 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 proprietary long-term pricing models that utilize certain market based inputs. See Note 9 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for fair value disclosures and discussion of fair value measurements.

FINANCIAL CONDITION

Liquidity and Capital Resources

Cash Flows — Cash provided by operating activities for the nine months ended September 30, 2010 and 2009 totaled $966 million and $1.743 billion, respectively. The decrease in cash provided of $777 million was driven by a $667 million effect of the amended accounting standard related to the accounts receivable securitization program (see Note 5 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010), under which the $383 million of funding under the program upon the January 1, 2010 adoption is reported as a use of operating cash flows and a source of financing cash flows, with subsequent 2010 activity reported as financing, while the $284 million of funding in 2009 is reported as operating cash flows. The remaining decrease of $110 million reflected the deconsolidation of Oncor, partially offset by higher earnings from the competitive business as adjusted for noncash items, reflecting the contribution of the new generation units.

Cash used in financing activities totaled $1.167 billion in 2010 compared to cash provided of $420 million in 2009. These activities are summarized below (see Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010):

	Nine Months Ended September 30,
	2010			2009
Net issuances, repayments and repurchases of borrowings	$	(1,448	)	$	389
Net contributions from and distributions to noncontrolling interests		24			10
Net short-term borrowings under accounts receivable securitization program		228			—
Other		29			21
Total provided by (used in) financing activities	$	(1,167	)	$	420

Cash used in investing activities decreased $1.820 billion driven by decreased capital expenditures and the return in 2010 of the collateral posted in 2009 related to interest rate swaps discussed in Note 11 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010. These activities are summarized below:

	Nine Months Ended September 30,
	2010			2009
Capital expenditures, including nuclear fuel	$	(793	)	$	(2,034	)
Redemption of investment held in money market fund		—			142
Investment redeemed/(posted) with counterparty		400			(400	)
Proceeds from sale of assets		141			41
Change in restricted cash		(31	)		118
Other		(24	)		6
Total used in investing activities	$	(307	)	$	(2,127	)

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The decline in capital spending for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009 reflected the deconsolidation of Oncor ($758 million capital expenditures in 2009) (see Note 3 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010) in 2010 and a decrease in spending related to the construction of the now substantially complete new generation facilities.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $278 million and $312 million for the nine months ended September 30, 2010 and 2009, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel cost in the statement of income consistent with industry practice, and 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 delivery fees, other income and interest expense and related charges.

Debt Financing Activity—Activities related to short-term borrowings and long-term debt during the nine months ended September 30, 2010 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):

	Borrowings (a)		Repayments and Repurchases (b)
TCEH	$	107	$	521
EFCH		—		3
EFIH		2,180		—
EFH Corp.		1,223		4,443
Total long-term		3,510		4,967
Total short-term — TCEH (c)		—		873
Total	$	3,510	$	5,840

(a) Includes the following activities (see Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010):

• $500 million of EFH Corp. 10% Notes issued by EFH Corp., the proceeds of which may be used in debt exchanges or repurchases.

• Principal increases in payment of accrued interest totaling $162 million and $107 million of EFH Corp. and TCEH Toggle Notes, respectively.

• $561 million of EFH Corp. 10% Notes issued by EFH Corp. in debt exchanges.

• $2.180 billion of EFIH 10% Notes issued by EFIH in debt exchanges.

(b) Includes $3.976 billion of noncash retirements (including discounts captured on cash repurchases) as a result of 2010 debt exchange and repurchase transactions discussed in Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010.

(c) Short-term amounts represent net borrowings/repayments.

See Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for further detail of long-term debt and other financing arrangements.

We, our affiliates or our agents may from time to time purchase our outstanding debt for cash in open market purchases or privately negotiated transactions (including pursuant to a Section 10b-5(1) plan) or via privately negotiated exchange transactions similar to the private exchange transactions completed in 2010, or we may refinance existing debt. We will evaluate any such transactions in light of market prices of the debt, taking into account 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.

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Available Liquidity — The following table summarizes changes in available liquidity for the nine months ended September 30, 2010 (excluding Oncor):

	Available Liquidity
	September 30, 2010		December 31, 2009		Change
Cash and cash equivalents	$	652	$	1,161	$	(509	)
TCEH Revolving Credit Facility (a)		2,620		1,721		899
TCEH Letter of Credit Facility		410		399		11
Subtotal	$	3,682	$	3,281	$	401
Short-term investment (b)		—		490		(490	)
Total liquidity (c)	$	3,682	$	3,771	$	(89	)

(a) As of September 30, 2010 and December 31, 2009, the TCEH Revolving Credit Facility includes $229 million and $141 million, respectively, of commitments from Lehman that are only available from the fronting banks and the swingline lender.

(b) December 31, 2009 amount includes $425 million cash investment (including accrued interest) and $65 million in letters of credit posted related to certain interest rate and commodity hedge transactions. Pursuant to the related agreement, the collateral was returned in March 2010. See Note 11 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010.

(c) As of September 30, 2010 and December 31, 2009, total liquidity includes $693 million and $520 million, respectively, of cash received for “margin deposits related to commodity positions” and is net of cash totaling $196 million and $187 million, respectively, posted with counterparties as “margin deposits related to commodity positions.”

Note: Available liquidity in the future could benefit from additional exercises of the payment-in-kind (PIK) option on the EFH Corp. Toggle Notes and TCEH Toggle Notes, which for the remaining payment dates from November 2010 through November 2012 would avoid cash interest payments of approximately $605 million.

See Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for additional discussion of the credit facilities.

Pension and OPEB Plan Funding— Pension and OPEB plan funding is expected to total $43 million and $24 million, respectively, in 2010. Oncor is expected to fund approximately 88% of this amount consistent with its share of the pension liability. We made pension and OPEB contributions of $28 million and $17 million, respectively, in the nine months ended September 30, 2010, of which $40 million was contributed by Oncor.

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

EFH Corp. made its May 2010 interest payment and will make its November 2010 interest payment on the EFH Corp. Toggle Notes by using the PIK feature of those notes. During such applicable interest periods, the interest rate on these notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the notes by $162 million in May 2010 and will further increase the aggregate principal amount of the notes by a currently estimated $32 million in November 2010 (excluding $130 million principal amount to be issued to EFIH as holder of $2.166 billion principal amount of EFH Corp. Toggle Notes acquired in the debt exchange completed in August 2010 that is eliminated in consolidation). The elections increased liquidity in May 2010 by an amount equal to $152 million and will further increase liquidity in November 2010 by an amount equal to a currently estimated $30 million (excluding $122 million related to notes held by EFIH), constituting the amounts of cash interest that otherwise would have been payable on the notes in May 2010 and November 2010, respectively.

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Similarly, TCEH made its May 2010 interest payment and will make its November 2010 interest payment on the TCEH Toggle Notes by using the PIK feature of those notes. During such applicable interest periods, the interest rate on these notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the notes by approximately $110 million in May 2010, including $3 million principal amount paid to EFH Corp. and eliminated in consolidation, and will further increase the aggregate principal amount of the notes by $102 million in November 2010, including $4 million principal amount paid to EFH Corp. and eliminated in consolidation. The elections increased liquidity in May 2010 by an amount equal to $100 million and will further increase liquidity in November 2010 by an amount equal to an estimated $91 million, constituting the amounts of cash interest that otherwise would have been payable on the notes in May 2010 and November 2010, respectively.

See Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for discussion of debt repurchase and exchange transactions in 2010 that resulted in redemption of portions of the outstanding principal of the EFH Corp. and TCEH Toggle Notes held by unaffiliated parties that are reflected in the amounts related to the May 2010 and November 2010 PIK elections.

Liquidity Effects of Commodity Hedging and Trading Activities — Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other forms of credit support to satisfy such collateral obligations. In addition, TCEH’s Commodity Collateral Posting Facility, an uncapped senior secured revolving 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, as of September 30, 2010, more than 95% of the long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral requirements for those hedging transactions. See Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for more information about this facility.

As of September 30, 2010, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $193 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $183 million posted as of December 31, 2009;

• $690 million in cash has been received from counterparties, net of $3 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $516 million received, net of $4 million in cash posted, as of December 31, 2009;

• $325 million in letters of credit have been posted with counterparties, as compared to $379 million posted as of December 31, 2009; and

• $44 million in letters of credit have been received from counterparties, as compared to $44 million received as of December 31, 2009.

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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 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. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing liquidity in the event that it was not restricted. As of September 30, 2010, restricted cash collateral held totaled $31 million. See Note 16 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 regarding restricted cash.

With the long-term hedging program, increases in natural gas prices generally result in increased cash collateral and letter of credit postings to counterparties. As of September 30, 2010, approximately 450 million MMBtu of positions related to the long-term hedging program were not directly secured on an asset-lien basis and thus have cash collateral posting requirements. The uncapped TCEH Commodity Collateral Posting Facility supports the collateral posting requirements related to substantially all of these transactions.

Income Tax Refunds/Payments — Income tax payments related to the Texas margin tax are expected to total approximately $60 million, and refunds of federal income taxes are expected to total approximately $30 million in the next 12 months. Payments in the nine months ended September 30, 2010 totaled $64 million.

Accounts Receivable Securitization Program — TXU Energy participates in EFH Corp.’s accounts receivable securitization program with financial institutions (the funding entities). As discussed in Note 1 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010, in accordance with amended transfers and servicing accounting standards, the trade accounts receivable amounts under the program are reported as pledged balances and the related funding amounts are reported as short-term borrowings. Under the program, TXU Energy (originator) sells retail trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp., which sells undivided interests in the purchased accounts receivable for cash to entities established for this purpose by the funding entities. All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $228 million and $383 million as of September 30, 2010 and December 31, 2009, respectively. See Note 5 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for a more complete description of the program including amendments to the program in June 2010, the impact of the program on the financial statements for the periods presented and the contingencies that could result in termination of the program and a reduction of liquidity should the underlying financing be settled.

Distributions from Oncor — Until December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor’s net income determined in accordance with GAAP, subject to certain defined adjustments. Distributions are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. (See Note 8 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010.)

In January 2009, the PUCT awarded CREZ construction projects to Oncor. See discussion below under “Regulatory Matters — Oncor Matters with the PUCT.” As a result of the increased capital expenditures for CREZ and the debt-to-equity ratio cap, we expect distributions to EFH Corp. from Oncor will be substantially reduced during the CREZ construction period.

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Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain of our financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of September 30, 2010, we were in compliance with all such covenants.

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

Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. Senior Secured Notes) for the twelve months ended September 30, 2010 totaled $5.195 billion for EFH Corp. The following are reconciliations of net income to Adjusted EBITDA for EFH Corp., TCEH and EFIH, respectively, for the nine and twelve months ended September 30, 2010 and 2009.

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EFH Corp.

Adjusted EBITDA Reconciliation

	Nine Months Ended September 30, 2010			Nine Months Ended September 30, 2009			Twelve Months Ended September 30, 2010			Twelve Months Ended September 30, 2009
Net income (loss) attributable to EFH Corp.	$	(2,973	)	$	207		$	(2,836	)	$	(8,648	)
Income tax expense		336			254			449			245
Interest expense and related charges		3,092			2,136			3,868			4,566
Depreciation and amortization		1,043			1,286			1,511			1,679
EBITDA	$	1,498		$	3,883		$	2,992		$	(2,158	)
Oncor EBITDA		—			(1,043	)		(311	)		(488	)
Oncor Holdings distributions/dividends (a)		141			117			239			1,487
Interest income		(9	)		(30	)		(24	)		(35	)
Amortization of nuclear fuel		102			73			130			95
Purchase accounting adjustments (b)		159			257			241			392
Impairment of goodwill		4,100			90			4,100			8,090
Impairment of assets and inventory write down (c)		3			5			40			715
Net gain on debt exchange offers		(1,166	)		—			(1,253	)		—
Net income (loss) attributable to noncontrolling interests		—			54			9			(106	)
Equity in earnings of unconsolidated subsidiary		(240	)		—			(240	)		—
EBITDA amount attributable to consolidated unrestricted subsidiaries		—			3			1			3
Unrealized net gain resulting from hedging transactions		(1,615	)		(713	)		(2,127	)		(3,263	)
Amortization of “day one” net loss on Sandow 5 power purchase agreement		(19	)		(7	)		(22	)		(7	)
Losses on sale of receivables		—			9			3			17
Noncash compensation expenses (d)		13			9			15			11
Severance expense (e)		3			9			4			10
Transition and business optimization costs (f)		(2	)		22			1			29
Transaction and merger expenses (g)		37			65			53			84
Insurance settlement proceeds (h)		—			—			—			(21	)
Restructuring and other (i)		(1	)		(10	)		(4	)		(6	)
Expenses incurred to upgrade or expand a generation station (j)		100			100			100			100
Adjusted EBITDA per Incurrence Covenant	$	3,104		$	2,893		$	3,947		$	4,949
Add back Oncor Adjusted EBITDA (reduced by Oncor distributions/dividends)		1,053			926			1,248			(148	)
Adjusted EBITDA per Restricted Payments Covenant	$	4,157		$	3,819		$	5,195		$	4,801

(a) Twelve months ended September 30, 2009 amount includes $1.253 billion distribution of net proceeds from the sale of Oncor noncontrolling interests in November 2008.

(b) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits not recognized in net income due to purchase accounting.

(c) Impairment of assets includes impairment of trade name intangible asset, impairments of land and the natural gas-fueled generation fleet and charges related to the cancelled development of coal-fueled generation facilities.

(d) Noncash compensation expenses are accounted for under accounting standards related to stock compensation and exclude capitalized amounts.

(e) Severance expense includes amounts incurred related to outsourcing, restructuring and other amounts deemed to be in excess of normal recurring amounts.

(f) Transition and business optimization costs include professional fees primarily for retail billing and customer care systems enhancements and incentive compensation.

(g) Transaction and merger expenses include costs related to the Merger and abandoned strategic transactions, outsourcing transition costs, administrative costs related to the cancelled program to develop coal-fueled generation facilities, the Sponsor Group management fee, costs related to certain growth initiatives and costs related to the Oncor sale of noncontrolling interests.

(h) Insurance settlement proceeds include the amount received for property damage to certain mining equipment.

(i) Restructuring and other for twelve months ended September 30, 2010 includes restructuring and nonrecurring activities and for the twelve months ended September 30, 2009 primarily represents reversal of certain liabilities accrued in purchase accounting and recorded as other income, partially offset by restructuring initiatives and nonrecurring activities.

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

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TCEH Consolidated

Adjusted EBITDA Reconciliation

	Nine Months Ended September 30, 2010			Nine Months Ended September 30, 2009			Twelve Months Ended September 30, 2010			Twelve Months Ended September 30, 2009
Net income (loss)	$	(3,646	)	$	493		$	(3,430	)	$	(7,559	)
Income tax expense		260			330			377			343
Interest expense and related charges		2,516			1,331			3,019			3,492
Depreciation and amortization		1,027			862			1,337			1,127
EBITDA	$	157		$	3,016		$	1,303		$	(2,597	)
Interest income		(65	)		(40	)		(89	)		(55	)
Amortization of nuclear fuel		102			73			130			95
Purchase accounting adjustments (a)		124			222			194			345
Impairment of goodwill		4,100			70			4,100			8,070
Impairment of assets and inventory write down (b)		1			2			35			710
EBITDA amount attributable to consolidated unrestricted subsidiaries		—			3			1			3
Unrealized net gain resulting from hedging transactions		(1,615	)		(713	)		(2,127	)		(3,263	)
Amortization of “day one” net loss on Sandow 5 power purchase agreement		(19	)		(7	)		(22	)		(7	)
Corporate depreciation, interest and income tax expenses included in SG&A expense		9			5			9			5
Losses on sale of receivables		—			9			3			17
Noncash compensation expense (c)		11			1			11			3
Severance expense (d)		3			9			4			10
Transition and business optimization costs (e)		2			22			5			26
Transaction and merger expenses (f)		29			3			30			12
Insurance settlement proceeds (g)		—			—			—			(21	)
Restructuring and other (h)		1			(15	)		(1	)		(15	)
Expenses incurred to upgrade or expand a generation station (i)		100			100			100			100
Adjusted EBITDA per Incurrence Covenant	$	2,940		$	2,760		$	3,686		$	3,438
Expenses related to unplanned generation station outages		122			61			152			93
Pro forma adjustment for Sandow 5 and Oak Grove 1 reaching 70% capacity in Q1 (j)		—			—			42			—
Other adjustments allowed to determine Adjusted EBITDA per Maintenance Covenant (k)		19			21			36			28
Adjusted EBITDA per Maintenance Covenant	$	3,081		$	2,842		$	3,916		$	3,559

(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits not recognized in net income due to purchase accounting.

(b) Impairment of assets includes impairment of trade name intangible asset and impairment of land and the natural gas-fueled generation fleet.

(c) Noncash compensation expenses are accounted for under accounting standards related to stock compensation and 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, outsourcing transition costs and costs related to certain growth initiatives.

(g) Insurance settlement proceeds include the amount received for property damage to certain mining equipment.

(h) Restructuring and other for the twelve months ended September 30, 2010 includes restructuring and nonrecurring activities, and for the twelve months ended September 30, 2009 primarily represents reversal of certain liabilities accrued in purchase accounting and recorded as other income, partially offset by restructuring and nonrecurring activities.

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

(j) Pro forma adjustment for Sandow 5 and Oak Grove 1 represents the annualization of the actual nine months ended September 30, 2010 EBITDA results for these two units.

(k) Primarily pre-operating expenses relating to Oak Grove 2.

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EFIH Consolidated

Adjusted EBITDA Reconciliation

	Nine Months Ended September 30, 2010			Nine Months Ended September 30, 2009			Twelve Months Ended September 30, 2010			Twelve Months Ended September 30, 2009
Net income (loss)	$	142		$	80		$	136		$	(593	)
Income tax benefit		(59	)		(70	)		(82	)		(91	)
Interest expense and related charges		233			207			305			273
Depreciation and amortization		—			—			—			—
EBITDA	$	316		$	217		$	359		$	(411	)
Oncor EBITDA		—			—			—			—
Oncor Holdings distributions/dividends (a)		141			117			239			1,487
Interest income		(76	)		—			(80	)		(2	)
Equity in earnings of unconsolidated subsidiary (net of tax)		(240	)		(217	)		(278	)		414
Other		—			1			—			1
Adjusted EBITDA per Incurrence Covenant	$	141		$	118		$	240		$	1,489
Add back Oncor Holdings Adjusted EBITDA (reduced by Oncor Holdings distributions/dividends)		1,053			926			1,248			(148	)
Adjusted EBITDA per Restricted Payments Covenant	$	1,194		$	1,044		$	1,488		$	1,341

(a) Twelve months ended September 30, 2009 amount includes $1.253 billion distribution of net proceeds from the sale of Oncor noncontrolling interests in November 2008.

The following table summarizes TCEH’s secured debt to Adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp., EFIH and TCEH that are applicable under certain other covenants in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the EFH Corp. Senior Notes, the EFH Corp. Senior Secured Notes and the EFIH Notes as of September 30, 2010 and December 31, 2009 and the corresponding maintenance and other covenant threshold levels as of September 30, 2010:

	September 30, 2010		December 31, 2009			Threshold Level as of September 30, 2010
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to Adjusted EBITDA ratio (a)		4.84 to 1.00		4.76 to 1.00			Must not exceed 7.00 to 1.00 (b)
Debt Incurrence Covenants:
EFH Corp. Senior Secured Notes:
EFH Corp. fixed charge coverage ratio		1.3 to 1.0		1.2 to 1.0			At least 2.0 to 1.0
TCEH fixed charge coverage ratio		1.5 to 1.0		1.5 to 1.0			At least 2.0 to 1.0
EFIH Notes:
EFIH fixed charge coverage ratio (c)		(d)		53.8 to 1.0			At least 2.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio		1.5 to 1.0		1.5 to 1.0			At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio		1.5 to 1.0		1.5 to 1.0			At least 2.0 to 1.0
Restricted Payments/Limitations on Investments Covenants:
EFH Corp. Senior Notes:
General restrictions (Sponsor Group payments):					��
EFH Corp. leverage ratio		8.5 to 1.0		9.4 to 1.0			Equal to or less than 7.0 to 1.0
EFH Corp. Senior Secured Notes:

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	September 30, 2010	December 31, 2009	Threshold Level as of September 30, 2010
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (e)	1.6 to 1.0	1.4 to 1.0		At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (e)	1.3 to 1.0	1.2 to 1.0		At least 2.0 to 1.0
EFH Corp. leverage ratio	8.5 to 1.0	9.4 to 1.0		Equal to or less than 7.0 to 1.0
EFIH Notes:
General restrictions (non-EFH Corp. payments):
EFIH fixed charge coverage ratio (c) (f)	14.3 to 1.0	3.9 to 1.0		At least 2.0 to 1.0
General restrictions (EFH Corp. payments):
EFIH fixed charge coverage ratio (c) (f)	(d)	53.8 to 1.0		At least 2.0 to 1.0
EFIH leverage ratio	5.5 to 1.0	4.4 to 1.0		Equal to or less than 6.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio	1.5 to 1.0	1.5 to 1.0		At least 2.0 to 1.0
TCEH Senior Secured Facilities:
Payments to Sponsor Group:
TCEH total debt to Adjusted EBITDA ratio	7.9 to 1.0	8.4 to 1.0		Equal to or less than 6.5 to 1.0

(a) In accordance with the terms of the TCEH Senior Secured Facilities and as the result of the new Sandow and first Oak Grove generating units achieving average capacity factors of greater than or equal to 70% for the three months ended March 31, 2010, the maintenance covenant as of September 30, 2010 includes pro forma twelve months Adjusted EBITDA for the units and the proportional amount of outstanding debt under the Delayed Draw Term Loan (see Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010) applicable to the two units.

(b) Threshold level will decrease to a maximum of 6.75 to 1.00 effective December 31, 2010 and 6.50 to 1.00 effective December 31, 2011. Calculation excludes debt that ranks junior to the TCEH Senior Secured Facilities.

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

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

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

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

Material Credit Rating Covenants and Credit Worthiness Effects on Liquidity — As a result of TCEH’s non-investment grade credit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, as of September 30, 2010, counterparties to those contracts could have required TCEH to post up to an aggregate of $8 million in additional collateral. This amount largely represents the below market terms of these contracts as of September 30, 2010; thus, this amount will vary depending on the value of these contracts on any given day.

Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. As of September 30, 2010, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $28 million, with $14 million of this amount posted for the benefit of Oncor.

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The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of September 30, 2010, TCEH posted letters of credit in the amount of $84 million, which are subject to adjustments. See “Regulatory Matters — Certification of REPs.”

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 (a subsidiary of TCEH) is not sufficient to support its reclamation obligations, TCEH may be required to post cash or letter of credit collateral support in an amount currently estimated to be approximately $650 million to $900 million. The actual amount (if required) could vary depending upon numerous factors, including Luminant Generation Company LLC’s credit worthiness and the level of mining reclamation obligations.

ERCOT 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 $36 million as of September 30, 2010 (which is subject to weekly adjustments based on settlement activity with ERCOT).

Other arrangements of EFH Corp. and its subsidiaries, including Oncor’s credit facility, the accounts receivable securitization program (see Note 5 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the relevant credit ratings.

In the event that any or all of the additional collateral requirements discussed above are triggered, we believe we 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 of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to the accounts receivable securitization program, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity of outstanding balances ($21.310 billion as of September 30, 2010) under such facilities.

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

Under the terms of a TCEH rail car lease, which had $45 million in remaining lease payments as of September 30, 2010 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

Under the terms of a TCEH rail car lease, which had $51 million in remaining lease payments as of September 30, 2010 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

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

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

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

We enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which vary, stated in the contracts. The subsidiaries whose default would trigger cross default vary depending on the contract.

Each of TCEH’s natural gas hedging agreements that are secured with a lien on its assets on a pari passu basis with the TCEH Senior Secured Facilities contains a cross default provision. In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but ranging from $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedging agreements would have the right to terminate its hedge 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 an aggregate derivative liability of $1.755 billion as of September 30, 2010 would have the right to terminate its interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.

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

Guarantees — See Note 7 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for details of guarantees.

OFF–BALANCE SHEET ARRANGEMENTS

See Notes 3 and 7 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 regarding VIEs and guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 7 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

See Note 1 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for a discussion of changes in accounting standards.

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REGULATORY MATTERS

Regulatory Investigations and Reviews

See Note 7 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010.

Certification of REPs

In April 2009, the PUCT finalized a rule relating to the Certification of Retail Electric Providers. The rule strengthens the certification requirements for REPs in order to better protect customers, transmission and distribution utilities (TDUs), and other REPs from the potential insolvency of REPs. The rule, among other things, increases creditworthiness and financial reporting requirements for REPs and provides additional customer protection requirements and regulatory asset consideration for TDU bad debt expenses. Under the new financial requirements, TXU Energy filed an amended certification, which became effective in March 2010. As a result, TCEH posted letters of credit in March 2010 totaling $84 million with the PUCT securing its payment obligations to TDUs, and is no longer required to reserve liquidity for such purposes. Liquidity reserved as of December 31, 2009 totaled $228 million.

Wholesale Market Design — Nodal Market

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

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

• operate a voluntary day-ahead energy market;

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

• use nodal energy prices for resources;

• provide information for energy trading hubs by aggregating nodes;

• use zonal prices for loads, and

• provide congestion revenue rights (CRRs) (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 instead of across the geographic zones. The implementation of a nodal market is being done in conjunction with transmission improvements designed to reduce current congestion. The implementation of a nodal market is scheduled for December 2010. While we cannot predict the ultimate impact of the proposed nodal wholesale market design on our operations or financial results, such change could ultimately have an adverse impact on the profitability and value of our competitive business, particularly if such change results in lower revenue due to lower wholesale power prices, increased costs or increased collateral posting requirements with ERCOT.

In 2010, ERCOT began conducting market testing activities in preparation for the December 2010 transition to the nodal market design. These testing activities have included certifying qualified scheduling entities (QSEs) to participate in the day-ahead and real-time markets, conducting market-wide tests of ERCOT’s nodal operation systems to deploy generation resources to maintain grid frequency, holding mock auctions related to CRRs and conducting simulations of day-ahead market operations with market participants. In addition to these operational market testing activities, ERCOT has provided simulated full financial settlement and calculation of simulated credit exposure and collateral requirements for each simulated operating day. We have participated in these activities and are currently fully certified for participating in both the day-ahead market and real-time operations. Additionally, all of our operational and mothballed generation assets and our QSEs have completed certification for operation in the nodal market. In October 2010, ERCOT’s board authorized nodal implementation to commence on December 1, 2010.

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Oncor Matters with the PUCT

Stipulation Approved by the PUCT— In April 2008, the PUCT entered an order, which became final in June 2008, approving the terms of a stipulation relating to the filing in 2007 by Oncor and Texas Holdings of a Merger-related Joint Report and Application with the PUCT pursuant to Section 14.101(b) of PURA and PUCT Substantive Rule 25.75. The stipulation required the filing of a rate case by Oncor no later than July 1, 2008 based on a test year ended December 31, 2007. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200^th District Court of Travis County, Texas. A hearing on the appeal was held in June 2010, and the District Court affirmed the PUCT order in its entirety. Nucor Steel has appealed that ruling. Oncor filed the rate case with the PUCT in June 2008, and the PUCT issued a final order with respect to the rate case in August 2009 as discussed in the 2009 Form 10-K. Oncor and four other parties appealed various portions of the rate case final order to a state district court. Oral argument was held on October 19, 2010. The judge has taken the matter under advisement, and Oncor anticipates receiving a ruling in November 2010.

Transmission Rates (PUCT Docket Nos. 37882, 38460 and 38495)— In order to recover increases in its transmission costs, including incremental fees paid to other transmission service providers due to an increase in their rates, Oncor is allowed to request an update twice a year to the transmission cost recovery factor (TCRF) component of its retail delivery rates charged to REPs. In January 2010, an application was filed to increase the TCRF, which was administratively approved in February 2010 and became effective March 1, 2010. This application is expected to increase annualized revenues by $13 million. In July 2010, an application was filed to increase the TCRF. It was administratively approved in August 2010 and became effective September 1, 2010. This application is expected to increase Oncor’s annualized revenues by $15 million.

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

PUCT Rulemaking— The PUCT has published rule changes in two proceedings that would impact transmission rates. In the first proceeding (PUCT Project No. 37909), the PUCT approved the proposal for adoption at its September 29, 2010 open meeting, which changes the TCRF rule to allow for more complete cost recovery of wholesale transmission charges incurred by distribution service providers. Previously, increased wholesale transmission charges were recoverable by distribution service providers, effective with the March 1 and September 1 TCRF updates, but distribution service providers could not recover increased charges incurred prior to such updates. TCRF filings are still effective March 1 and September 1, but distribution service providers will be allowed to include wholesale transmission charges based on the effective date of the wholesale transmission rate changes. In the second proceeding (PUCT Project No. 37519), the PUCT approved the proposal for adoption at its July 30, 2010 open meeting, making changes to the wholesale transmission rules to allow transmission service providers to update their wholesale transmission rates twice in a calendar year, as compared to once per year under the previous rules, providing more timely recovery of incremental capital investment. Other changes included in this rule (i) tie the effective date of the biannual update portion of the rule to the effective date of the TCRF rule in Project No. 37909, (ii) require the PUCT to consider the effects of reduced regulatory lag when setting rates in the next full rate case and (iii) provide for administrative approval of uncontested interim wholesale transmission rate applications.

Application for 2011 Energy Efficiency Cost Recovery Factor (PUCT Docket No. 38217) — In April 2010, Oncor filed an application with the PUCT to request approval of an energy efficiency cost recovery factor (EECRF) for 2011. PUCT rules require Oncor to make an annual EECRF filing by May 1 for implementation at the beginning of the next calendar year. In September 2010, the PUCT ruled that Oncor will be allowed to recover $51 million through its 2011 EECRF, including $45 million for 2011 program costs and an $11 million performance bonus based on 2009 results as well as a $5 million reduction for over-recovery of 2009 costs, as compared to $54 million recovered through its 2010 EECRF. The resulting monthly charge for residential customers will be $0.91, as compared to the 2010 residential charge of $0.89 per month.

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Competitive Renewable Energy Zones (CREZs) — In January 2009, the PUCT awarded approximately $1.3 billion of CREZ construction projects to Oncor (PUCT Docket Nos. 35665 and 37902). The projects involve the construction of transmission lines to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of the state. The cost estimates for the CREZ construction projects were based upon cost analyses prepared by ERCOT in April 2008. Based on the selection of final routes for the three default and nine priority projects, identification of additional costs not included in the original ERCOT estimate (e.g., wind interconnection facilities and required modifications to existing facilities) and Oncor’s preferred routes for the remaining five subsequent projects, Oncor currently estimates that the cost of these projects will be approximately $1.75 billion. Individual project costs could change based on final route specifications for the subsequent projects determined by the PUCT. In addition, ERCOT is currently performing a study to determine what additional facilities need to be built to provide additional voltage support to the state’s transmission grid as a result of CREZ, and the outcome of this study could result in additional CREZ project costs. Oncor cannot estimate those additional costs at this time. It is expected that ERCOT will release the results of the study by the end of 2010. As of September 30, 2010, Oncor’s cumulative CREZ-related capital expenditures totaled $256 million, including $142 million during the nine months ended September 30, 2010. It is expected that the necessary permitting actions and other requirements and all construction activities for Oncor’s CREZ construction projects will be completed by the end of 2013.

In October 2009, the PUCT initiated a proceeding (Docket No. 37567) to determine whether there was sufficient financial commitment from generators of renewable energy to grant Certificates of Convenience and Necessity for transmission facilities located in two areas in the panhandle of Texas designated as CREZs. Three of the CREZ transmission projects awarded to Oncor are located in the two CREZs that are the subject of the proceeding. The estimated cost of these three transmission projects is approximately $380 million and is included in the $1.75 billion estimate above. In July 2010, a stipulation and proposed order was filed that would allow these projects to proceed. The PUCT approved the proposed order and issued its written order on July 30, 2010.

In July 2009, the City of Garland, Texas filed an Original Petition and Application for Stay and Injunction in the 200^th District Court of Travis County, Texas seeking judicial review and a stay of the PUCT’s March 2009 written order selecting transmission service providers (including Oncor) to build CREZ transmission facilities. In January 2010, the district court issued an order reversing the PUCT’s order and remanding it to the PUCT for action consistent with the court’s opinion. The district court order did not contain a stay or injunction and severed the City of Garland’s requests for declaratory and injunctive relief. In February 2010, the PUCT issued orders that severed certain of the CREZ transmission projects awarded to Oncor and others from its consideration of the remand of the written order (PUCT Docket No. 37928) and suspended the schedule sequencing CREZ projects subsequent to CREZ priority projects (PUCT Docket No. 36802). In April 2010, the PUCT issued an order in Docket No. 36802 establishing the sequencing for CREZ projects subsequent to priority projects, which did not affect Oncor other than resulting in the schedule for Oncor to file CCN applications for its five CREZ subsequent projects between May and September 2010 as compared to the original March to May 2010 timeframe. That order excludes two CREZ subsequent projects that had been originally awarded to Lower Colorado River Authority, and the PUCT opened Docket No. 38045 to award these two projects. In July 2010, the City of Garland and South Texas Electric Cooperative filed a participation agreement regarding these two projects. In September 2010, the PUCT awarded the projects to the City of Garland and South Texas Electric Cooperative.

Sunset Review— PURA, the PUCT, the RRC, ERCOT, the TCEQ and the Office of Public Utility Counsel (OPUC) will be subject to “sunset” review by the Texas Legislature in the 2011 legislative session. Sunset review includes, generally, a comprehensive review of the need for and effectiveness of an administrative agency (the PUCT, the RRC, ERCOT, the TCEQ or the OPUC), along with an evaluation of the advisability of any changes to that agency’s authorizing legislation (PURA). A Sunset staff report on the PUCT offering various recommendations for consideration by the Sunset Commission was issued in April 2010, and the related Sunset public meeting was conducted in May 2010. The Sunset Commission met in July 2010 and adopted various recommendations regarding the PUCT, ERCOT and the OPUC. A Sunset staff report on the RRC is scheduled to be issued in October 2010, and the related Sunset public meeting is scheduled for November 2010. The Sunset Commission will submit its recommendations for the Texas Legislature’s consideration during the next session, which begins in January 2011. We cannot predict the outcome of the sunset review process.

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Mine Safety Disclosures — Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act

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

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

Disclosures related to specific mines pursuant to Section 1503 of the recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act sourced from data documented as of October 7, 2010 in the MSHA Data Retrieval System for the three months ended September 30, 2010 (except pending legal actions, which are as of September 30, 2010) are as follows:

Mine (a)	Section 104 S and S Citations (b)		Proposed MSHA Assessments ($ thousands) (c)		Pending Legal Action (d)
Beckville		1		1		1
Big Brown		1		2		1
Kosse		—		1		—
Oak Hill		4		—		1
Sulphur Springs		2		1		2
Tatum		—		—		1
Three Oaks		1		3		—
Winfield South		1		3		1

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

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

(c) Total dollar value for proposed assessments received from MSHA for all citations and orders issued in the three months ended September 30, 2010, including but not limited to Sections 104, 107 and 110 citations and orders that are not required to be reported.

(d) Pending actions before the FMSHRC involving a coal or other mine.

During the three months ended September 30, 2010, our mining operations received no citations, orders or written notices under Sections 104(b), 104(d), 104(e), 107(a) or 110(b)(2) of the Mine Act, and they experienced no fatalities.

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Summary

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

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Risk Oversight

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

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

Commodity Price Risk

TCEH is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. The company actively manages its portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. The company, 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, TCEH enters into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. The company continuously monitors the valuation of identified risks and adjusts positions based on current market conditions. The company strives to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

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

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

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

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

	Nine Months  Ended September 30, 2010		Year Ended December 31, 2009
Month-end average Trading VaR:	$	3	$	4
Month-end high Trading VaR:	$	4	$	7
Month-end low Trading VaR:	$	1	$	2

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, 2010		Year Ended December 31, 2009
Month-end average MtM VaR:	$	450	$	1,050
Month-end high MtM VaR:	$	621	$	1,470
Month-end low MtM VaR:	$	321	$	638

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, 2010		Year Ended December 31, 2009
Month-end average EaR:	$	507	$	1,088
Month-end high EaR:	$	662	$	1,511
Month-end low EaR:	$	404	$	676

The decreases in the risk measures (MtM VaR and EaR) above were primarily driven by changes in market volatility and underlying commodity prices.

Interest Rate Risk

As of September 30, 2010, the potential reduction of annual pretax earnings due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled $40 million, taking into account the interest rate swaps discussed in Note 6 to EFH Corp.’s historical condensed consolidated financial statements for three and nine months ended September 30, 2010.

Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty’s financial condition, credit rating and other quantitative and qualitative credit criteria and 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. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties’ financial strength, measurement of current and potential future exposures and contract language that provides rights for netting and set-off. Credit enhancements such as parental guarantees, letters of credit, surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to assess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering into an agreement with a counterparty that creates exposure. Additionally, we have established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material 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 — Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions (before credit collateral) arising from commodity contracts and hedging and trading activities totaled $3.251 billion as of September 30, 2010. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of September 30, 2010 include $885 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $71 million. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.

The remaining credit exposure arises from wholesale trade receivables, commodity contracts and hedging and trading activities, including interest rate hedging. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. As of September 30, 2010, the exposure to credit risk from these counterparties totaled $2.366 billion taking into account the standardized master netting contracts and agreements described above but before taking into account $714 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $1.652 billion increased $355 million in the nine months ended September 30, 2010, reflecting the increase in derivative assets related to the long-term hedging program due to the decline in forward natural gas prices, partially offset by the return of the $400 million in collateral discussed in Note 11 to EFH Corp.’s historical condensed consolidated financial statements for three and nine months ended September 30, 2010.

Of this $1.652 billion net exposure, essentially all is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and our internal credit evaluation process. Those customers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties on this basis.

The following table presents the distribution of credit exposure as of September 30, 2010 arising from wholesale trade receivables, commodity contracts and hedging and trading activities. This credit exposure represents wholesale trade accounts receivable and net asset positions on the balance sheet arising from hedging and trading activities after taking into consideration netting provisions within each contract, setoff provisions in the event of default and any master netting contracts with counterparties. See Note 11 to EFH Corp.’s historical condensed consolidated financial statements for three and nine months ended September 30, 2010 for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.

	Exposure Before  Credit Collateral			Credit Collateral		Net Exposure			Gross Exposure by Maturity
									2 years  or less		Between 2-5  years		Greater than 5  years		Total
Investment grade	$	2,333		$	712	$	1,621		$	1,576	$	757	$	—	$	2,333
Noninvestment grade		33			2		31			31		2		—		33
Totals	$	2,366		$	714	$	1,652		$	1,607	$	759	$	—	$	2,366
Investment grade		98.6	%				98.1	%
Noninvestment grade		1.4	%				1.9	%

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

Significant (10% or greater) concentration of credit exposure exists with two counterparties, which represented 49% and 29% of the net $1.652 billion exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and the importance of our business relationship with the counterparty. However, this concentration increases the risk that a default would have a material effect on results of operations.

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS AS OF AND FOR THE YEAR

ENDED DECEMBER 31, 2009

The following discussion and analysis of our financial condition and results of operations covers fiscal years ended December 31, 2009 and 2008, and was included in EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2009 filed with the SEC on February 19, 2010 (except for disclosure regarding credit ratings, which has been deleted to comply with an intervening change in law). You should read this MD&A in conjunction with the “Selected Historical Consolidated Financial Data for EFH Corp. and Its Subsidiaries” and EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 and the notes to those statements, each included elsewhere in this prospectus. This MD&A should also be read in conjunction with the disclosure set forth in “Prospectus Summary — Recent Developments,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010” and EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 and the notes to those statements, each included elsewhere in this prospectus and each of which provides material updates to certain of the information contained in this MD&A. This MD&A 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 this MD&A with “Our Businesses” 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 this MD&A refer to Energy Future Holdings Corp. and/or its subsidiaries, depending on context. See “Glossary” for other defined terms used in this MD&A. All dollar amounts in the tables in this MD&A are stated in millions of U.S. dollars unless otherwise indicated.

BUSINESS

We are a Dallas-based holding company conducting operations principally through our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority-owned (approximately 80%) subsidiary engaged in regulated electricity transmission and distribution operations in Texas. Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. See Note 1 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for a description of the material features of these “ring-fencing” measures and Note 15 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of noncontrolling interests sold by Oncor.

Operating Segments

We have aligned and report our business activities as two operating segments: the Competitive Electric segment and the Regulated Delivery segment. The Competitive Electric segment is principally comprised of TCEH. The segment also includes equipment salvage and resale activities related to the cancellation of the development of eight new coal-fueled generation units in 2007. The Regulated Delivery segment is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary.

See Note 24 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for further information regarding reportable business segments.

Significant Activities and Events

Long-Term Hedging Program — TCEH 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, the company has entered into market transactions involving natural gas-related financial instruments, and as of December 31, 2009, has effectively sold forward approximately 1.6 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 200,000 GWh at an assumed 8.0 market heat rate) for the period from January 1, 2010 through December 31, 2014 at weighted average annual hedge prices ranging from $7.80 per MMBtu to $7.19 per MMBtu. These transactions, as well as forward power sales, have effectively hedged an estimated 68% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning January 1, 2010 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which is expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.

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The long-term hedging program is comprised primarily of contracts with prices based on the New York Mercantile Exchange (NYMEX) Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. The company has hedged more than 95% of the Houston Ship Channel versus Henry Hub pricing point risk for 2010.

The company has entered into related put and call transactions (referred to as collars), primarily for year 2014 of the program, that effectively hedge natural gas prices within a range. These transactions represented approximately 6% of the positions in the long-term hedging program at December 31, 2009, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. The company expects to use financial instruments, including collars, in future hedging activity under the long-term hedging program.

The following table summarizes the natural gas hedges in the long-term hedging program as of December 31, 2009:

Measure

2010

2011

2012

2013

2014

Total

Natural gas hedge volumes (a)

mm MMBtu

~240

~447

~490

~300

~97

~1,574

Weighted average hedge price (b)

$/MMBtu

~7.79

~7.56

~7.36

~7.19

~7.80

—

Weighted average market price (c)

$/MMBtu

~5.79

~6.34

~6.53

~6.67

~6.84

—

(a) Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity (i.e., delta position) of the derivatives. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 97 million MMBtu in 2014.

(b) Weighted average hedge prices are based on NYMEX Henry Hub prices of forward natural gas sales positions in the long-term hedging program (excluding the impact of offsetting purchases for rebalancing and pricing point basis transactions). Where collars are reflected, sales price represents the collar floor price.

(c) Based on NYMEX Henry Hub prices.

Changes in the fair value of the instruments in the long-term hedging program are being recorded as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities in the statement of income, which has and could continue to result in significant volatility in reported net income. Based on the size of the long-term hedging program as of December 31, 2009, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $1.6 billion in pretax unrealized mark-to-market gains or losses.

The reported unrealized mark-to-market net gain related to the long-term hedging program for the year ended December 31, 2009 totaled $1.107 billion. This amount reflects a $1.857 billion net gain due to the effect of lower forward prices of natural gas on the value of positions in the program, which was partially offset by net losses of $750 million representing reversals of previously recorded unrealized gains on positions that settled in the period. The reported unrealized mark-to-market net gain related to the long-term hedging program for the year ended December 31, 2008 totaled $2.587 billion reflecting declines in forward prices of natural gas in 2008. Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains or losses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices and will in this context be viewed as having resulted in an opportunity cost. The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $1.978 billion and $871 million at December 31, 2009 and December 31, 2008, respectively. These values can change materially as market conditions change.

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As of December 31, 2009, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility — see discussion below under “Financial Condition — Liquidity and Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.

See “Key Risks and Challenges — Substantial Leverage, Uncertain Financial Markets and Liquidity Risk” and “— Natural Gas Price and Market Heat Rate Exposure.”

Debt Exchanges and Issuances— See Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of debt exchange offers completed in November 2009 and the issuance of additional notes in January 2010.

TCEH Interest Rate Swap Transactions —As of December 31, 2009, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $16.30 billion principal amount of its senior secured debt maturing from 2010 to 2014. All of these swaps were entered into prior to January 1, 2009. Taking into consideration these swap transactions, approximately 10% of our total long-term debt portfolio at December 31, 2009 was exposed to variable interest rate risk. TCEH also entered into interest rate basis swap transactions, which further reduce the fixed (through swaps) borrowing costs, related to an aggregate of $16.25 billion principal amount of senior secured debt. We may enter into additional interest rate hedges from time to time. Unrealized mark-to-market net gains and losses related to all TCEH interest rate swaps, which are reported in interest expense and related charges, totaled $696 million in net gains for the year ended December 31, 2009 and $1.477 billion in net losses for the year ended December 31, 2008. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.212 billion and $1.909 billion at December 31, 2009 and 2008, respectively, of which $194 million and $364 million (both pre-tax), respectively, was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. See discussion in Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 regarding various interest rate swap transactions.

Texas Generation Facilities Development —TCEH is nearing completion of a program to develop three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in Texas with a total estimated capacity of approximately 2,200 MW. The Sandow unit and the first Oak Grove unit achieved substantial completion (as defined in the EPC agreements for the units) effective September 30, 2009 and December 22, 2009, respectively. Accordingly, the company has operational control of these units. We began depreciating these units and recognizing revenues and fuel costs for accounting purposes in the fourth quarter 2009. The second Oak Grove unit, which is in the commissioning and start-up phase, synchronized to the grid in January 2010 and is expected to achieve substantial completion (as defined in the EPC agreement for the unit) in mid-2010. 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 $3.1 billion was spent as of December 31, 2009. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $4.8 billion upon completion of the units, and the balance was $4.6 billion as of December 31, 2009. See discussion in Note 13 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 regarding contingencies related to these units.

Nuclear Generation Development — In September 2008, a subsidiary of TCEH filed a combined operating license application with the NRC for two new nuclear generation units, each with approximately 1,700 MW (gross capacity), at its existing Comanche Peak nuclear generation site. In connection with the filing of the application, in January 2009, subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, Comanche Peak Nuclear Power Company (CPNPC), to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. The TCEH subsidiary owns an 88% interest in CPNPC, and a MHI subsidiary owns a 12% interest.

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In March 2009, the NRC announced an official review schedule for the license application. Based on the schedule, the NRC expects to complete its review by December 2011, and it is expected that a license would be issued approximately one year later. In November 2009, CPNPC filed a comprehensive revision to the license application that updated the license application for developments occurring after the initial filing.

In 2009, the DOE announced that it had selected four applicants to proceed to the due diligence phase of its Loan Guarantee Program, and to commence negotiations towards potential loan guarantees for their respective generation projects. CPNPC was not among the initial four applicants selected by the DOE; however, CPNPC continues to update the DOE on its progress, with the goal of securing a DOE loan guarantee for financing the proposed units prior to commencement of construction.

Idling of Natural Gas-Fueled Units — In February 2009, we notified ERCOT of plans to retire 11 of our natural gas-fueled units, totaling 2,251 MW of capacity (2,341 MW installed nameplate capacity), in May 2009, and mothball (idle) an additional four units, totaling 1,651 MW of capacity (1,675 MW of installed nameplate capacity), in September 2009. In May and September 2009, we entered into reliability-must-run (RMR) agreements for the remainder of 2009 with ERCOT for the operation of one unit originally planned to be retired with 112 MW of capacity (115 MW of installed nameplate capacity) and one unit planned to be mothballed with 515 MW of capacity (540 MW of installed nameplate capacity), respectively. In December 2009, we entered into RMR agreements with ERCOT for these same two units for January through November 2010. The other units were retired in May 2009 or mothballed in September 2009 as originally planned. An impairment charge of $229 million related to the carrying value of these units was recorded in the fourth quarter of 2008.

Global Climate Change — See “Our Businesses — Environmental Regulations and Related Considerations” for discussion of global climate change and the effects on the company.

Impairment of Goodwill — Financial market conditions had a significant effect on our 2008 assessment of the carrying value of goodwill. We recorded a total goodwill impairment charge of $8.950 billion (which was not deductible for income tax purposes) in 2008 and 2009, primarily arising from the dislocation in the capital markets that had increased interest rate spreads and the resulting discount rates used in estimating fair values and the effects of declines in market values of debt and equity securities of comparable companies.

This non-cash impairment did not cause EFH Corp. or its subsidiaries to be in default under any of their respective debt covenants or impact counterparty trading agreements or have a material impact on liquidity.

See Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 and “Application of Critical Accounting Policies” below for more information on the goodwill impairment charge.

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. Oncor’s plans provide for the full deployment of over three million advanced meters by the end of 2012 to all residential and most non-residential retail electricity customers in Oncor’s service area. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits.

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As of December 31, 2009, Oncor has installed approximately 660 thousand advanced digital meters, including approximately 620 thousand during the year ended December 31, 2009. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $196 million as of December 31, 2009.

As discussed below under “Regulation and Rates,” Oncor has implemented a rate surcharge effective January 1, 2009 to recover its investment in the advanced meter deployment.

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

KEY RISKS AND CHALLENGES

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

Substantial Leverage, Uncertain Financial Markets and Liquidity Risk

Our substantial leverage, resulting in large part from debt incurred to finance the Merger, requires significant cash flows to be dedicated to interest and principal payments and could adversely affect our ability to raise additional capital to fund operations, limit our ability to react to changes in the economy, our industry or our business, and expose us to interest rate risk to the extent not hedged. Short-term borrowings and long-term debt, including amounts due currently, totaled $43.426 billion at December 31, 2009. Taking into consideration interest-rate swap transactions, as of December 31, 2009 approximately 90% of our total long-term debt portfolio is subject to fixed interest rates, at a weighted average interest rate of 8.95%. Interest payments on long-term debt in 2010 are expected to total approximately $3.059 billion, and principal payments are expected to total approximately $340 million.

While we believe our cash on hand and cash flow from operations combined with availability under existing credit facilities provide sufficient liquidity to fund current and projected expenses and capital requirements for 2010 (see “Financial Condition — Liquidity and Capital Resources” section below), there can be no assurance that counterparties to our credit facilities will perform as expected through the maturity dates or hedging and trading counterparties, particularly related to the long-term hedging program, will meet their obligations to us. Failure of such counterparties to meet their obligations or substantial changes in financial markets, the economy, the requirements of regulators or our industry or operations could result in constraints in our liquidity. See discussion of credit risk in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” in our 2009 Form 10-K and discussion of credit facilities in “Financial Condition — Liquidity and Capital Resources” and in Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009. Also, as a result of the financial crisis that arose in 2008, there has been a reduction of available counterparties for our hedging and trading activities, particularly for longer-dated transactions, which could impact our ability to hedge our commodity price and interest rate exposure to desired levels at reasonable costs. However, traditional counterparties with physical assets to hedge, as well as financial institutions and other parties, continue to participate in the markets.

A substantial amount of our indebtedness is scheduled to mature in the period from 2014 through 2017. We are focused on improving the balance sheet and expect to opportunistically look for ways to reduce the amount and extend the weighted average maturity of our outstanding debt. Progress to date on this initiative includes the August 2009 amendment to the Credit Agreement governing the TCEH Senior Secured Facilities that provides additional flexibility in restructuring debt obligations, the debt exchanges completed in November 2009 and the January 2010 issuance of $500 million of senior secured notes to be used for general corporate purposes, including but not limited to, repurchase of outstanding indebtedness. See Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for additional discussion of these transactions.

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In addition, because our operations are capital intensive, we expect to rely over the long-term upon access to financial markets as a significant source of liquidity for capital requirements not satisfied by cash-on-hand, operating cash flows or our available credit facilities. Our ability to economically access the capital or credit markets could be restricted at a time when we would like, or need, to access those markets. Lack of such access could have an impact on our flexibility to react to changing economic and business conditions.

Natural Gas Price and Market Heat-Rate Exposure

Wholesale electricity prices in the ERCOT market generally move with the price of natural gas because marginal demand for electricity supply is generally met with natural gas-fueled generation facilities. Historically the price of natural gas has fluctuated due to the effects of weather, changes in industrial demand, supply availability, and other economic and market factors and such prices have been very volatile in recent years. Since 2005, forward natural gas prices ranged from below $4 per MMBtu to above $13 per MMBtu. The wholesale market price of power divided by the market price of natural gas represents the market heat rate. Market heat rate movements also affect wholesale electricity prices. Market heat rate reflects the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity.

In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating electricity from our nuclear and lignite/coal-fueled plants. All other factors being equal, these baseload generation assets, which provided 70% of supply volumes in 2009, increase or decrease in value as natural gas prices and market heat rates rise or fall, respectively, because of the effect of natural gas prices setting marginal wholesale power prices in ERCOT.

With the exposure to variability of natural gas prices, retail sales price management and hedging activities are critical to the profitability of the business and maintaining consistent cash flow levels.

Our approach to managing commodity price risk focuses on the following:

• employing disciplined hedging and risk management strategies through physical and financial energy-related (electricity and natural gas) contracts intended to partially hedge gross margins;

• continuing reduction of fixed costs to better withstand gross margin volatility;

• following a retail pricing strategy that appropriately reflects the magnitude and costs of commodity price and liquidity risk, and

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

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

The following sensitivity table provides estimates of the potential impact (in $millions) of movements in natural gas and certain other commodity prices and market heat rates on realized pre-tax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH’s unhedged position and forward prices as of December 31, 2009, which for natural gas reflects estimates of electricity generation less amounts hedged through the long-term natural gas hedging program and amounts under existing wholesale and retail sales contracts. On a rolling twelve-month basis, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.

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	Balance 2010 (a)		2011		2012		2013		2014
$1.00/MMBtu change in gas price (b)	$	~9	$	~45	$	~89	$	~308	$	~512
0.1/MMBtu/MWh change in market heat rate (c)	$	~10	$	~44	$	~54	$	~57	$	~59
$1.00/gallon change in diesel fuel price	$	~1	$	~1	$	~2	$	~53	$	~57
$10.00/pound change in uranium/nuclear fuel	$	—	$	—	$	~1	$	~5	$	~4

(a) Balance of 2010 is from February 1, 2010 through December 31, 2010.

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

(c) Based on Houston Ship Channel natural gas prices as of December 31, 2009.

Our market heat rate exposure is impacted by changes in the mix of generation assets, such as generation capacity increases, particularly increases in lignite/coal- and nuclear-fueled generation capacity, as well as wind capacity, which could result in lower market heat rates. We expect that decreases in market heat rates would decrease the value of our generation assets because lower market heat rates generally result in lower wholesale electricity prices, and vice versa. We mitigate market heat rate risk through retail and wholesale electricity sales contracts and shorter-term market heat rate hedging transactions. We evaluate opportunities to mitigate market heat rate risk over extended periods through longer-term electricity sales contracts where practical considering pricing, credit, liquidity and related factors.

On an ongoing basis, we will continue monitoring our overall commodity risks and seek to balance our portfolio based on our desired level of exposure to natural gas prices and market heat rates and potential changes to our operational forecasts of overall generation and consumption (which is also subject to volatility resulting from customer churn, weather, economic and other factors) in our native and growth business. Portfolio balancing may include the execution of incremental transactions, including heat rate hedges, the unwinding of existing transactions and the substitution of natural gas hedges with commitments for the sale of electricity at fixed prices. As a result, commodity price exposures and their effect on earnings could materially change from time to time.

The Obama Administration has proposed financial market reforms with respect to the currently unregulated Over-the-Counter (OTC) financial derivatives market. As a result, the U.S. House of Representative has approved a bill to regulate OTC derivatives. The bill would require certain entities to clear OTC derivatives that are currently traded on the bilateral market through exchanges, which require that all collateral be in the form of cash. We have entered into a significant number of asset-backed OTC derivatives to hedge risks associated with commodity and interest rate exposure. The U.S. House of Representatives legislation would not require us to clear our OTC derivatives through exchanges. However, other proposals would have required such clearing, and it is not evident what, if any, U.S. Senate legislation might be approved. If we were required to clear such transactions, we would likely be precluded from using our noncash assets as collateral for hedging arrangements. This preclusion could have a material impact on our liquidity, particularly if the final legislation does not provide for the grandfathering of existing OTC derivatives. As a result, if applied to our OTC derivatives transactions, legislation that impairs the use of asset-backed transactions could significantly increase our costs of entering into OTC derivatives and/or could significantly limit our ability to enter into OTC derivatives and hedge our commodity and interest rate risks. We cannot predict whether or when final legislation will be enacted or whether the U.S. House of Representatives bill exemptions will be included in any final legislation.

See “Financial Condition — Liquidity and Capital Resources” below for a discussion of the liquidity effects of the long-term hedging program. Also see additional discussion of risk under Item 7A, “Quantitative and Qualitative Disclosures about Market Risk” in our 2009 Form 10-K.

Competitive Retail Markets and Customer Retention

Competitive retail activity in Texas has resulted in some volatility in retail customer counts. Total retail customer counts decreased less than 1% in 2007, rose 2% in 2008 and declined 3% in 2009. In responding to the competitive landscape in the ERCOT marketplace, we are focusing on the following key initiatives:

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• Maintaining competitive pricing initiatives as evidenced by price reductions on most residential service plans in 2008 and 2009, in addition to the 15% cumulative price reduction in 2007 applicable to residential customers under qualifying service plans;

• Profitably growing the retail customer base by actively competing for new and existing customers in areas in Texas open to competition. The customer retention strategy remains focused on continuing to implement initiatives to deliver world-class customer service and improve the overall customer experience;

• Establishing TXU Energy as the most innovative retailer in the Texas market by continuing to develop tailored product offerings to meet customer needs. TXU Energy plans to invest $100 million over the five-year period beginning in 2008 (including $20 million invested through 2009) in retail initiatives aimed at helping consumers conserve energy and other demand-side management initiatives that are intended to moderate consumption and reduce peak demand for electricity, and

• Focusing business market initiatives largely on programs targeted to retain the existing highest-value customers and to recapture customers who have switched REPs. Initiatives include maintaining and continuously refining a disciplined contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and marketing efforts and to more effectively deploy the direct-sales force. Tactical programs put into place include improved customer service, aided by a new customer management system implemented in 2009, the successful operation of which is critical to customer satisfaction, new product price/service offerings and a multichannel approach for the small business market.

Volatile Energy Prices and Regulatory Risk

Natural gas prices rose to unprecedented levels in the latter part of 2005, reflecting a world-wide increase in energy prices compounded by hurricane-related infrastructure damage. The related rise in electricity prices elevated public awareness of energy costs and dampened customer demand. Natural gas prices remain subject to events that create price volatility, and while not reaching 2005 levels, forward natural gas prices rose substantially in 2007 and part of 2008 before falling in the second half of 2008 and continuing to fall through most of 2009. 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. We believe that competitive markets result in a broad range of innovative pricing and service alternatives to consumers and ultimately the most efficient use of resources and regulatory entities should continue to take actions that encourage competition in the industry. Regulatory and/or legislative intervention could disrupt the relationship between natural gas prices and electricity prices, which could impact the results of our long-term hedging strategy and our results of operations.

New and Changing Environmental Regulations

We are 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. We are in compliance with all current laws and regulations, but regulatory authorities continue to evaluate existing requirements and consider proposals for changes. We continue to closely monitor any potential legislative and regulatory changes pertaining to global climate change. In view of the fact that a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities, our financial condition or results of operations could be materially adversely affected by the enactment of any legislation, regulation or judicial action that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes on entities that produce GHG emissions. For example, federal, state or regional legislation or regulation addressing global climate change could result in us either incurring increased material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with a mandatory cap-and-trade emissions reduction program or incurring increased taxes, which could be material, due to the imposition of a carbon tax. See further discussion under, “Our Businesses — Environmental Regulations and Related Considerations.”

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Exposures Related to Nuclear Asset Outages

Our nuclear assets are comprised of two generation units at Comanche Peak, each with an installed nameplate capacity of 1,150 MW. The Comanche Peak plant represents approximately 13% of our total generation capacity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage, the unfavorable impact to pretax earnings is estimated to be approximately $2 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 13 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

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.

Other Matters

See Note 13 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of litigation related to our new lignite-fueled generation facility construction program and “Regulation and Rates” for discussion of ERCOT’s planned implementation of a nodal market.

APPLICATION OF CRITICAL ACCOUNTING POLICIES

Our significant accounting policies are discussed in Note 1 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009. We follow accounting principles generally accepted in the U.S. Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain critical accounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.

Purchase Accounting

In 2007, the Merger was accounted for under purchase accounting, whereby the purchase price of the transaction was allocated to our 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 accounting standards related to the determination of fair value (see Note 16 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009) 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 our assets. For example, the valuation of the baseload generation facilities considered our lignite fuel reserves and mining capabilities.

The results of the purchase price allocation included an increase in the total carrying value of our baseload generation plants and the recording of intangible assets related to the retail customer base, the TXU Energy trade name and emission credits. Further, commodity and other contracts not already subject to fair value accounting were valued, and amounts representing favorable or unfavorable contracts (versus market conditions as of the date of the Merger) were recorded as intangible assets or liabilities, respectively. Management believes all material intangible assets were identified. See Notes 2 and 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for details of the purchase price allocation and intangible assets recorded, respectively.

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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 25 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 regarding adjustments to the carrying values of Oncor’s regulatory asset and related long-term debt.

The excess of the purchase price over the estimated fair values of the net assets acquired was recorded as goodwill. The goodwill amount recorded upon finalization of purchase accounting totaled $23.2 billion. Management believes the drivers of the goodwill amount included 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 reflected 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 accounting guidance related to goodwill and other intangible assets, goodwill is not amortized to net income, but is required to be tested for impairment at least annually. This guidance requires that goodwill be assigned to “reporting units,” which management has determined to be the Competitive Electric segment and the Regulated Delivery segment, which are almost entirely comprised of TCEH and Oncor, respectively. The assignment of goodwill was based on the relative estimated enterprise values of the operations as of the date of the Merger using discounted cash flow methodologies. Goodwill amounts assigned totaled $18.3 billion to the Competitive Electric segment and $4.9 billion to the Regulated Delivery segment. None of this goodwill balance is being deducted for tax purposes.

In the first quarter of 2009 and fourth quarter of 2008, we recorded goodwill impairment charges totaling $8.950 billion. The $90 million charge in the first quarter of 2009 resulted from the completion of the previously estimated fair value calculations supporting the initial $8.860 billion goodwill impairment charge that was recorded in the fourth quarter of 2008. See discussion immediately below under “Impairment of Assets.”

Impairment of Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist, in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. One of those indications is a current expectation that “more likely than not” a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life (as was the case for the natural gas-fueled generation assets discussed below). For our 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 our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual plants that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing.

Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually or whenever events or changes in circumstances indicate an impairment may exist, such as the possible impairments to long-lived assets discussed above. Effective with 2009 testing, we changed the annual test date for goodwill and intangible assets with indefinite useful lives from October 1 to December 1. Management determined the new annual goodwill test date is preferable because of efficiencies gained by aligning the test with our annual budget and five-year plan processes in the fourth quarter. The change in the annual test date did not delay, accelerate or avoid an impairment charge, and retrospective application of this change in accounting principle did not affect previously reported results. As required by accounting guidance related to goodwill and other intangible assets, we have allocated goodwill to our reporting units, which are our two segments: Competitive Electric and Regulated Delivery, and goodwill impairment testing is performed at the reporting unit level. Under this goodwill impairment analysis, if at the assessment date, a reporting unit’s carrying value exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair values of the reporting unit’s operating assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill amount is then compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied goodwill amount is written off as an impairment charge.

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The determination of enterprise value involves a number of assumptions and estimates. We use a combination of three fair value inputs to estimate enterprise values of our reporting units: internal discounted cash flow analyses (income approach), comparable company equity values and any recent pending and/or completed relevant transactions. The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, generation plant performance and retail sales volume trends. Another key variable in the income approach is the discount rate, or weighted average cost of capital. The determination of the discount rate takes into consideration the capital structure, debt ratings and current debt yields of comparable companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry. Enterprise value estimates based on comparable company equity values involve using trading multiples of EBITDA of those selected companies to derive appropriate multiples to apply to the EBITDA of the reporting units. This approach requires an estimate, using historical acquisition data, of an appropriate control premium to apply to the reporting unit values calculated from such multiples. Critical judgments include the selection of comparable companies and the weighting of the three value inputs in developing the best estimate of enterprise value.

The 2009 annual impairment testing performed as of October 1, and December 1, 2009 for goodwill and intangible assets with indefinite useful lives in accordance with accounting guidance for a change in annual impairment testing dates resulted in no impairment (see discussion in Note 1 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 regarding change in the annual impairment test date from October 1 to December 1). The goodwill testing determined that the estimated fair value (enterprise value) of the Regulated Delivery segment exceeded its carrying value by approximately 10% resulting in no additional testing being required and no impairment for the segment. Key assumptions in the valuation of the regulated business include discount rates, growth of the rate base and return on equity allowed by the regulatory authority. Cash flows of the regulated business are relatively stable and more predictable than the competitive business. The Competitive Electric segment carrying value exceeded its estimated enterprise value (by less than 10%), so the estimated enterprise value of the segment was compared to the estimated fair values of its operating assets and liabilities. This additional testing indicated that the implied goodwill amount exceeded the recorded goodwill amount, and thus no goodwill impairment was recorded. The estimated enterprise value of the Competitive Electric segment reflects the impact of the decline in forward natural gas prices on wholesale electricity prices. Because lower wholesale electricity prices also result in lower fair values of our generation assets, calculated implied goodwill was sufficient to support the recorded goodwill amount. Key variables in the tests included forward natural gas prices, electricity prices, market heat rates and discount rates, assumptions regarding each of which could have a significant effect on valuations. Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.

See Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for a discussion of the goodwill impairment charges of $8.860 billion and $90 million (not deductible for income tax purposes) recorded in the fourth quarter of 2008 and first quarter of 2009, respectively. The total $8.950 billion impairment charge represented approximately 39% of the goodwill balance resulting from purchase accounting for the Merger and reflected a decline of approximately 20% in the estimated value of EFH Corp. at year-end 2008 from the indicated value at the October 2007 Merger date. The impairment primarily arose from the dislocation in the capital markets that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies in the second half of 2008. Also see Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of the impairment charge of $481 million ($310 million after-tax) related to the trade name intangible asset also recorded in the fourth quarter of 2008. The estimated fair value of this intangible asset is based on an assumed royalty methodology.

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In the fourth quarter of 2008, we recorded an impairment charge of $229 million ($147 million after-tax) related to our natural gas-fueled generation facilities. The natural gas-fueled generation units are generally operated to meet peak demands for electricity, and the facilities tested for impairment as an asset group. See Note 5 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 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. See “Business — Significant Activities and Events” for discussion of natural gas-fueled units mothballed (idled) or retired in 2009 consistent with the factors that resulted in the impairment.

In 2007, we recorded a net charge totaling $757 million ($492 million after-tax) (substantially all of which was in the Predecessor period) in connection with the 2007 suspension and subsequent cancellation of the development of eight coal-fueled generation units. This decision and subsequent terminations of equipment orders required an evaluation and substantial judgments regarding the recoverability of recorded assets associated with the development program. In determining the net charges recorded, we applied accounting rules for impairment of long-lived assets under guidance related to impairment or disposal of long-lived assets and for exit activities under guidance related to accounting for costs associated with exit or disposal activities. See Note 4 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for additional discussion.

Derivative Instruments and Mark-to-Market Accounting

We enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Under accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.

Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. We adopted new accounting standards related to the determination of fair value concurrent with the Merger and estimate fair value as described in Note 16 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 and discussed under “Fair Value Measurements” below.

Accounting standards related to derivative instruments and hedging activities allow for “normal” purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. These elections and designations are intended to match the accounting recognition of the contract’s financial performance to that of the transaction the contract is intended to hedge. “Normal” purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting.

Under hedge accounting, changes in fair value of instruments designated as cash flow hedges are recorded in other comprehensive income with an offset to derivative assets and liabilities to the extent the change in value is effective; that is, it mirrors the offsetting change in fair value of the forecasted hedged transaction. Changes in value that represent ineffectiveness of the hedge are recognized in net income immediately, and the effective portion of changes in fair value initially recorded in other comprehensive income are recognized in net income in the period that the hedged transactions are recognized. Although as of December 31, 2009, we do not have any derivatives designated as cash flow or fair value hedges, we continually assess our hedge elections and could designate positions as cash flow hedges in the future. In March 2007, the instruments making up a significant portion of the long-term hedging program that were previously designated as cash flow hedges were dedesignated as allowed under accounting standards related to derivative instruments and hedging activities, and subsequent changes in their fair value are being marked-to-market in net income. In addition, in August 2008, interest rate swap transactions in effect at that time were dedesignated as cash flow hedges in accordance with accounting standards, and subsequent changes in their fair value are being marked-to-market in net income. See further discussion of the long-term hedging program and interest rate swap transactions above under “Business — Significant Activities and Events.”

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The following tables provide the effects on both net income and other comprehensive income of mark-to-market accounting for those derivative instruments that we have determined to be subject to fair value measurement under accounting standards related to derivative instruments and hedging activities.

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Amounts recognized in net income (after-tax):
Unrealized net gains (losses) on positions marked-to-market in net income (a)	$	1,573		$	518		$	(955	)	$	(492	)
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the period (a)		(333	)		25			(56	)		(36	)
Unrealized ineffectiveness net gains (losses) on positions accounted for as cash flow hedges		—			(3	)	$	—			74
Reversals of previously recognized unrealized net (gains) losses related to cash flow hedge positions settled in the period		1			—			—			(15	)
Total	$	1,241		$	540		$	(1,011	)	$	(469	)
Amounts recognized in other comprehensive income (after-tax):
Net losses in fair value of positions accounted for as cash flow hedges	$	(20	)	$	(183	)	$	(177	)	$	(288	)
Net (gains) losses on cash flow hedge positions recognized in net income to offset hedged transactions		130			122			—			(89	)
Total	$	110		$	(61	)	$	(177	)	$	(377	)

(a) Amounts for 2009 and 2008 include $788 million and $1.503 billion in net after-tax gains related to commodity positions, respectively, and $452 million in net after-tax gains and $960 million in net after-tax losses related to interest rate swaps, respectively. Prior period amounts are essentially all related to commodity positions.

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

	Successor
	December 31, 2009			December 31, 2008
Net commodity contract asset (a)	$	1,714		$	466
Net derivative liability related to interest rate hedges		(1,242	)		(1,944	)
Net accumulated other comprehensive loss included in shareholders’ equity (amounts after tax)	$	(128	)	$	(238	)

(a) 2009 amount includes $4 million in net derivative liabilities and 2008 amount includes $7 million in net derivative assets related to cash flow hedge positions not marked-to-market in net income.

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Fair Value Measurements

In addition to purchase accounting, we apply fair value accounting on a recurring basis to certain assets and financial instruments under the fair value hierarchy established in accounting standards related to the determination of fair value. We utilize several valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These techniques include, but are not limited to, the use of broker quotes and statistical relationships between different price curves and are intended to maximize the use of observable inputs and minimize the use of unobservable inputs. In applying the market approach, we use a mid-market valuation convention (the mid-point between bid and ask prices) as a practical expedient.

Level 1 and Level 2 assets and liabilities consist primarily of commodity-related contracts for natural gas and electricity derivative instruments entered into for hedging purposes, securities associated with the nuclear decommissioning trust, and interest rate swaps intended to fix and/or lower interest payments on long-term debt. Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Level 2 valuations are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences. Level 2 inputs include:

• quoted prices for similar assets or liabilities in active markets;

• quoted prices for identical or similar assets or liabilities in markets that are not active;

• inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals, and

• inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Examples of Level 2 valuation inputs utilized include over-the-counter broker quotes and quoted prices for similar assets or liabilities that are corroborated by correlation or through statistical relationships between different price curves. For example, certain physical power derivatives are executed for a particular location at specific time periods that might not have active markets; however, an active market might exist for such derivatives for a different time period at the same location. We utilize correlation techniques to compare prices for inputs at both time periods to provide a basis to value the non-active derivative. (See Note 16 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for additional discussion of how broker quotes are utilized.)

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

Valuations of Level 3 assets and liabilities are sensitive to the assumptions used for the significant inputs. Where market data is available, the inputs used for valuation reflect that information as of our valuation date. In periods of extreme volatility, lessened liquidity or in illiquid markets, there may be more variability in market pricing or a lack of market data to use in the valuation process. An illiquid market is one in which little or no observable activity has occurred or one that lacks willing buyers. Valuation risk is mitigated through the performance of stress testing of the significant inputs to understand the impact that varying assumptions may have on the valuation and other review processes performed to ensure appropriate valuation.

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As part of our valuation of assets subject to fair value accounting, counterparty credit risk is taken into consideration by measuring the extent of netting arrangements in place with the counterparty along with credit enhancements and the estimated credit rating of the counterparty. Our valuation of liabilities subject to fair value accounting takes into consideration the market’s view of our credit risk along with the existence of netting arrangements in place with the counterparty and credit enhancements posted by us. We consider the credit risk adjustment to be a Level 3 input since judgment is used to assign credit ratings, recovery rate factors and default rate factors.

Level 3 assets totaled $350 million and $283 million at December 31, 2009 and 2008, respectively, and represented approximately 8% and 7%, respectively, of the assets measured at fair value, or less than 1% of total assets. Level 3 liabilities totaled $269 million and $355 million at December 31, 2009 and 2008, respectively, and represented approximately 8% and 7%, respectively, of the liabilities measured at fair value, or less than 1% of total liabilities.

Valuations of several of our Level 3 assets and liabilities are based on long-dated price curves for electricity that are developed internally. Additionally, Level 3 assets and liabilities are sensitive to changes in discount rates, option-pricing model inputs such as volatility factors and credit risk adjustments. As of December 31, 2009, a $5.00 per MWh change in electricity price assumptions across unobservable inputs, primarily related to the outer years in our long-dated pricing model (years that are not market observable) would cause an approximate $72 million change in net Level 3 assets. A 10% change in diesel fuel price assumptions across unobservable inputs would cause an approximate $11 million change in net Level 3 assets. In addition, we have derivative contracts that are valued based on option-pricing models with unobservable inputs. A 10% increase in volatility and correlation related to these contracts would cause an approximate $5 million change in net Level 3 assets. See Note 16 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for additional information about fair value measurements, including a table presenting the changes in Level 3 assets and liabilities for the twelve months ended December 31, 2009.

Revenue Recognition

Our revenue includes an estimate for unbilled revenue that represents estimated daily kWh consumption after the meter read date to the end of the period multiplied by the applicable billing rates. Estimated daily kWh usage is derived using historical kWh usage information adjusted for weather and other measurable factors affecting consumption. Calculations of unbilled revenues during certain interim periods are generally subject to more estimation variability because of seasonal changes in demand. Accrued unbilled revenues totaled $546 million, $505 million and $477 million at December 31, 2009, 2008 and 2007, respectively.

Accounting for Contingencies

Our financial results may be affected by judgments and estimates related to loss contingencies. A significant contingency that we account for is the loss associated with uncollectible trade accounts receivable. The determination of such bad debt expense is based on factors such as historical write-off experience, aging of accounts receivable balances, changes in operating practices, regulatory rulings, general economic conditions, effects of hurricanes and other natural disasters and customers’ behaviors. Changes in customer count and mix due to competitive activity and seasonal variations in amounts billed add to the complexity of the estimation process. Historical results alone are not always indicative of future results, causing management to consider potential changes in customer behavior and make judgments about the collectability of accounts receivable. Bad debt expense totaled $113 million, $81 million, $13 million and $46 million for the years ended December 31, 2009 and 2008, the period from October 11, 2007 to December 31, 2007 and the period from January 1, 2007 to October 10, 2007, respectively. The increase in bad debt in 2009 reflected higher delinquencies due to delays in final bills and disconnects resulting from a customer billing and information management system conversion, customer losses and general economic conditions. Amounts in 2008 reflected competitive customer acquisitions in south Texas and the effects of Hurricane Ike. See Note 10 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 regarding a reserve recorded in 2008 for amounts due from subsidiaries of Lehman.

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Litigation contingencies also may require significant judgment in estimating amounts to accrue. We accrue liabilities for litigation contingencies when such liabilities are considered probable of occurring and the amount is reasonably estimable. No significant amounts have been accrued for such contingencies during the three-year period ended December 31, 2009. See Item 3, “Legal Proceedings” in our 2009 Form 10-K for discussion of major litigation.

Accounting for Income Taxes

Our income tax expense and related balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. Our income tax returns are regularly subject to examination by applicable tax authorities. In management’s opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that may be owed as a result of any examination.

As discussed in Note 8 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009, in January 2007 we adopted new accounting standards that provide interpretive guidance for accounting for uncertain tax positions. See Notes 1 and 9 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of income tax matters.

Depreciation and Amortization

Depreciation expense related to generation facilities is based on the estimates of fair value and economic useful lives as determined in the application of purchase accounting described above. The accuracy of these estimates directly affects the amount of depreciation expense. If future events indicate that the estimated lives are no longer appropriate, depreciation expense will be recalculated prospectively from the date of such determination based on the new estimates of useful lives.

The estimated remaining lives range from 23 to 60 years for the lignite/coal- and nuclear-fueled generation units. See Note 1 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 under “Property, Plant and Equipment” for discussion of the change from composite to asset-by-asset depreciation effective with the Merger.

As a result of cost-based regulatory rate-setting processes, the book value of the majority of Oncor’s assets and liabilities effectively represent fair value, and no adjustments to those regulated assets or liabilities were recorded as part of purchase accounting for the Merger. Depreciation expense for such assets totaled $394 million, $330 million and $298 million in 2009, 2008 and 2007, or 3.1% of carrying value in 2009 and 2.8% in 2008 and 2007.

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 EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for additional information.

Regulatory Assets

The financial statements at December 31, 2009 and 2008, reflect total regulatory assets of $2.170 billion and $2.071 billion, respectively. These amounts include $759 million and $865 million, respectively, of generation-related regulatory assets recoverable by securitization (transition) bonds as discussed immediately below. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. (See “Oncor’s Regulatory Assets and Liabilities” in Note 25 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.)

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Generation-related regulatory asset stranded costs arising prior to the 1999 Restructuring Legislation became subject to recovery through issuance of $1.3 billion principal amount of transition bonds in accordance with a regulatory financing order. The carrying value of the regulatory asset upon final issuance of the bonds in 2004 represented the projected future cash flows to be recovered from REPs by Oncor through revenues as a transition charge to service the principal and fixed rate interest on the bonds. The regulatory asset is being amortized to expense in an amount equal to the transition charge revenues being recognized. As discussed in Note 2 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009, the regulatory asset and related transition bonds were adjusted to fair value on the date of the Merger in accordance with purchase accounting rules.

Other regulatory assets that we believe are probable of recovery, but are subject to review and possible disallowance, totaled $148 million at December 31, 2009. These amounts consist primarily of storm-related service recovery costs and employee retirement costs.

In August 2009, the PUCT issued a final order in Oncor’s first rate review in more than seven years. As discussed in Note 25 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009, the order resulted in a write off of regulatory assets of $25 million.

Defined Benefit Pension Plans and OPEB Plans

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

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

Benefit costs are impacted by actual 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
	Year Ended December 31,
	2009			2008
Pension costs	$	44		$	21		$	(1	)	$	34
OPEB costs		70			58			11			49
Total benefit costs	$	114		$	79		$	10		$	83
Less amounts deferred principally as a regulatory asset or property		(66	)		(42	)		(8	)		(43	)
Net amounts recognized as expense	$	48		$	37		$	2		$	40
Discount rate (a)		6.90	%		6.55	%		6.45	%		5.90	%

(a) Discount rate for OPEB was 6.85% in 2009.

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See Note 21 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 regarding other disclosures related to pension and OPEB obligations.

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

Assumption	Increase/(decrease) in 2009 Pension and OPEB Costs
Discount rate — 1% increase	$	(36	)
Discount rate — 1% decrease	$	44
Expected return on assets — 1% increase	$	(22	)
Expected return on assets — 1% decrease	$	22

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 Successor for the year ended December 31, 2009 to those of the Successor for the year ended December 31, 2008, by comparing the results of operations and cash flows of the Successor for the three months ended December 31, 2008 to those of the Successor for the period October 11, 2007 through December 31, 2007 and by comparing the results of operations and cash flows of the Successor for the nine months ended September 30, 2008 to those of the Predecessor for the period January 1, 2007 through October 10, 2007. To facilitate the discussion, certain volumetric and statistical data for 2008 have been presented as of and for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007 and as of and for the three months ended December 31, 2008 compared to the three months ended December 31, 2007. Such volumetric and statistical data are measured and reported on a monthly, quarterly and annual basis.

RESULTS OF OPERATIONS

Consolidated Financial Results

	Successor															Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Three Months Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Nine Months Ended September 30, 2008			Period from January 1, 2007 through October 10, 2007
Operating revenues	$	9,546		$	11,364		$	2,364		$	1,994		$	9,001		$	8,044
Fuel, purchased power costs and delivery fees		(2,878	)		(4,595	)		(728	)		(644	)		(3,867	)		(2,381	)
Net gain (loss) from commodity hedging and trading activities		1,736			2,184			2,432			(1,492	)		(248	)		(554	)
Operating costs		(1,598	)		(1,503	)		(383	)		(306	)		(1,120	)		(1,107	)
Depreciation and amortization		(1,754	)		(1,610	)		(393	)		(415	)		(1,217	)		(634	)

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	Successor															Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Three Months Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Nine Months Ended September 30, 2008			Period from January 1, 2007 through October 10, 2007
Selling, general and administrative expenses		(1,068	)		(957	)		(245	)		(216	)		(712	)		(691	)
Franchise and revenue-based taxes		(359	)		(363	)		(104	)		(93	)		(259	)		(282	)
Impairment of goodwill		(90	)		(8,860	)		(8,860	)		—			—			—
Other income		204			80			37			14			43			69
Other deductions		(97	)		(1,301	)		(718	)		(61	)		(583	)		(841	)
Interest income		45			27			5			24			22			56
Interest expense and related charges		(2,912	)		(4,935	)		(2,431	)		(839	)		(2,505	)		(671	)
Income (loss) from continuing operations before income taxes		775			(10,469	)		(9,024	)		(2,034	)		(1,445	)		1,008
Income tax (expense) benefit		(367	)		471			9			673			462			(309	)
Income (loss) from continuing operations		408			(9,998	)		(9,015	)		(1,361	)		(983	)		699
Income from discontinued operations, net of tax effect		—			—			—			1			—			24
Net income (loss)		408			(9,998	)		(9,015	)		(1,360	)		(983	)		723
Net (income) loss attributable to noncontrolling interests		(64	)		160			160			—			—			—
Net income (loss) attributable to EFH Corp.	$	344		$	(9,838	)	$	(8,855	)	$	(1,360	)	$	(983	)	$	723

Consolidated Financial Results — Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

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.

Operating revenues decreased $1.818 billion, or 16%, to $9.546 billion in 2009.

• Operating revenues in the Competitive Electric segment decreased $1.876 billion, or 19%, to $7.911 billion.

• Operating revenues in the Regulated Delivery segment increased $110 million, or 4%, to $2.690 billion.

• Net intercompany sales eliminations increased $52 million, reflecting Oncor’s higher distribution revenues from REP subsidiaries of TCEH.

Fuel, purchased power costs and delivery fees decreased $1.717 billion, or 37%, to $2.878 billion in 2009, driven by lower purchased power costs. See discussion below in the analysis of Competitive Electric segment results of operations.

Net gains from commodity hedging and trading activities totaled $1.736 billion in 2009 and $2.184 billion in 2008. Results in 2009 and 2008 included unrealized mark-to-market net gains totaling $1.277 billion and $2.281 billion, respectively, driven by the effect of lower forward market prices of natural gas on the value of positions in the long-term hedging program. See discussion below in the analysis of Competitive Electric segment results of operations.

Operating costs increased $95 million, or 6%, to $1.598 billion in 2009.

• Operating costs in the Competitive Electric segment increased $16 million, or 2%, to $693 million.

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• Operating costs in the Regulated Delivery segment increased $80 million, or 10%, to $908 million.

Depreciation and amortization increased $144 million, or 9%, to $1.754 billion in 2009.

• Depreciation and amortization in the Competitive Electric segment increased $80 million, or 7%, to $1.172 billion.

• Depreciation and amortization in the Regulated Delivery segment increased $65 million, or 13%, to $557 million.

SG&A expenses increased $111 million, or 12%, to $1.068 billion in 2009.

• SG&A expenses in the Competitive Electric segment increased $59 million, or 9%, to $741 million.

• SG&A expenses in the Regulated Delivery segment increased $30 million, or 18%, to $194 million.

• Corporate and Other SG&A expenses increased $22 million, or 20%, to $133 million driven by higher transition costs associated with outsourced support services.

See Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of the $90 million and $8.860 billion impairments of goodwill in 2009 and 2008, respectively.

Other income totaled $204 million in 2009 and $80 million in 2008, including $39 million and $44 million, respectively, in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. The 2009 amount also included an $87 million debt extinguishment gain (see discussion of debt exchanges in Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009), $23 million of income arising from the reversal of a use tax accrual recorded in purchase accounting related to periods prior to the Merger, which was triggered by a state ruling in the third quarter of 2009, and $21 million of income arising from the reversal of exit liabilities recorded in purchase accounting due to sooner than expected transition of outsourcing services (see Notes 2 and 20 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009). The 2008 amount also included a $21 million net insurance recovery for damage to certain mining equipment.

Other deductions totaled $97 million in 2009 and $1.301 billion in 2008. The 2009 amount included an impairment charge of $34 million related to land expected to be sold within the next 12 months and a $25 million write off of regulatory assets as discussed in Note 25 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 under “Oncor’s Regulatory Assets and Liabilities.” The 2008 amount included impairment charges of $501 million related to NO_x and SO₂ environmental allowances intangible assets and $481 million related to trade name intangible assets, both discussed in Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009, $229 million in impairment charges related to the natural gas-fueled generation facilities 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 filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code. See Note 10 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for details of other income and deductions.

Interest income increased $18 million, or 67%, to $45 million driven by interest on $465 million in collateral under a funding arrangement described in Note 18 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

Interest expense and related charges decreased $2.023 billion to $2.912 billion in 2009 reflecting a $696 million unrealized mark-to-market net gain related to interest rate swaps in 2009 as compared to a $1.477 billion net loss in 2008, which was partially offset by $118 million in increased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges and a $34 million decrease in capitalized interest. See Note 25 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

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Income tax expense totaled $367 million in 2009 compared to an income tax benefit of $471 million in 2008. The effective rate on income in 2009 was 47.4%, and the effective rate on a loss in 2008 was 4.5%. The increase in the rate reflects the impacts of nondeductible goodwill impairments of $90 million in 2009 and $8.860 billion in 2008, which increased the effective rate by 5.0 percentage points in 2009 and decreased the effective rate by 24.8 percentage points in 2008. The increase also reflects the effect of interest accrued for uncertain tax positions, which increased the rate on income in 2009 and decreased the rate on a loss in 2008.

Reflecting the goodwill and other impairment charges recorded in 2008, after tax-results improved $10.406 billion to $408 million in net income in 2009.

• After-tax results in the Competitive Electric segment improved $9.560 billion to $631 million in net income in 2009.

• After-tax results in the Regulated Delivery segment improved $806 million to $320 million in net income in 2009.

• Corporate and Other net expenses totaled $543 million in 2009 and $583 million in 2008. The amounts in 2009 and 2008 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The after-tax decrease of $40 million reflected the debt extinguishment gain of $57 million and $16 million in interest income related to the collateral discussed above, partially offset by a $20 million goodwill impairment charge and the $14 million increase in SG&A expense as discussed above.

Consolidated Financial Results — Three Months Ended December 31, 2008 Compared to Successor Period From October 11, 2007 Through December 31, 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.

Operating revenues increased $370 million, or 19%, to $2.364 billion in 2008.

• Operating revenues in the Competitive Electric segment increased $308 million, or 18%, to $1.979 billion.

• Operating revenues in the Regulated Delivery segment increased $80 million, or 15%, to $612 million.

• Net intercompany sales eliminations increased $18 million, reflecting Oncor’s higher distribution revenues from REP subsidiaries of TCEH.

Fuel, purchased power costs and delivery fees increased $84 million, or 13%, to $728 million in 2008. See discussion below in the analysis of Competitive Electric segment results of operations.

Net gain (loss) from commodity hedging and trading activities totaled $2.432 billion in net gains in 2008 compared to $1.492 billion in net losses in 2007. Results in 2008 included $2.586 billion in unrealized mark-to-market net gains, and results in 2007 included $1.556 billion in unrealized mark-to-market net losses driven by the effect of changes in forward market prices of natural gas on the value of positions in the long-term hedging program. See discussion below in the analysis of Competitive Electric segment results of operations.

Operating costs increased $77 million, or 25%, to $383 million in 2008.

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• Operating costs in the Competitive Electric segment increased $53 million, or 43%, to $177 million.

• Operating costs in the Regulated Delivery segment increased $26 million, or 14%, to $208 million.

Depreciation and amortization decreased $22 million, or 5%, to $393 million in 2008.

• Depreciation and amortization in the Competitive Electric segment decreased $50 million, or 16%, to $265 million.

• Depreciation and amortization in the Regulated Delivery segment increased $26 million, or 27%, to $122 million.

SG&A expenses increased $29 million, or 13%, to $245 million in 2008.

• SG&A expenses in the Competitive Electric segment increased $29 million, or 19%, to $183 million.

• SG&A expenses in the Regulated Delivery segment decreased $7 million, or 16%, to $38 million.

• Corporate and Other SG&A expenses increased $7 million, or 41%, to $24 million due primarily to incentive compensation and benefits expenses.

See Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of the $8.860 billion goodwill impairment charge recorded in the fourth quarter of 2008.

Other income totaled $37 million in 2008 and $14 million in 2007, including $11 million and $10 million, respectively, in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. The 2008 amount also included a $21 million net insurance recovery for damage to certain mining equipment. Other deductions totaled $718 million in 2008 and $61 million in 2007. The 2008 amount included impairment charges of $481 million related to trade name intangible assets and $229 million related to the natural gas-fueled generation fleet. The 2007 amount included $51 million of professional fees incurred related to the Merger. See Note 10 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for details of other income and deductions.

Interest expense and related charges increased $1.592 billion to $2.431 billion in 2008. The increase in interest expense and related charges was partially due to $27 million in expense and charges attributable to the ten fewer days in the 2007 period. The increase reflects increased rates, which includes an unrealized mark-to-market net loss on interest rate swaps of $1.512 billion, and higher average borrowings, partially offset by increased capitalized interest.

Income tax benefit totaled $9 million in 2008 compared to $673 million in 2007. The effective rate on a loss in 2008 was 5.5%, excluding the impact of the $8.860 billion goodwill impairment charge (this nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion), and the effective rate on a loss in 2007 was 33.1%. The decrease in the rate was driven by an increase in interest accrued for uncertain tax positions.

Reflecting the goodwill impairment charge in 2008, after-tax results declined $7.655 billion to a loss of $9.015 billion in 2008.

• After-tax results in the Competitive Electric segment declined $6.822 billion to a loss of $8.067 billion in 2008.

• After-tax results in the Regulated Delivery segment declined $858 million to a loss of $795 million in 2008.

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• Corporate and Other net expenses totaled $153 million in 2008 and $178 million in 2007. The amounts in 2008 and 2007 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The decrease of $25 million was driven by financial advisory, legal and other professional fees in 2007 directly related to the Merger.

Consolidated Financial Results — Nine Months Ended September 30, 2008 Compared to Predecessor Period From January 1, 2007 Through October 10, 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.

Operating revenues increased $957 million, or 12%, to $9.001 billion in 2008.

• Operating revenues in the Competitive Electric segment increased $925 million, or 13%, to $7.809 billion.

• Operating revenues in the Regulated Delivery segment decreased $18 million, or less than 1%, to $1.969 billion.

• Net intercompany sales eliminations decreased $50 million, reflecting lower sales by Oncor to REP subsidiaries of TCEH.

Fuel, purchased power costs and delivery fees increased $1.486 billion, or 62%, to $3.867 billion in 2008. See discussion below in the analysis of Competitive Electric segment results of operations.

Net gain (loss) from commodity hedging and trading activities totaled $248 million in net losses in 2008 compared to $554 million in net losses in 2007. Results in 2008 included unrealized mark-to-market net losses totaling $305 million driven by the effect of higher forward market prices of natural gas on the value of hedge positions. See discussion below in the analysis of Competitive Electric segment results of operations.

Operating costs increased $13 million, or 1%, to $1.120 billion in 2008.

• Operating costs in the Competitive Electric segment increased $29 million, or 6%, to $500 million.

• Operating costs in the Regulated Delivery segment decreased $17 million, or 3%, to $620 million.

Depreciation and amortization increased $583 million, or 92%, to $1.217 billion in 2008.

• Depreciation and amortization in the Competitive Electric segment increased $574 million to $827 million.

• Depreciation and amortization in the Regulated Delivery segment increased $4 million, or 1%, to $370 million.

SG&A expenses increased $21 million, or 3%, to $712 million in 2008.

• SG&A expenses in the Competitive Electric segment increased $10 million, or 2%, to $499 million.

• SG&A expenses in the Regulated Delivery segment decreased $13 million, or 9%, to $126 million.

• Corporate and Other SG&A expenses increased $24 million, or 38%, to $87 million due primarily to Sponsor management fees of $26 million.

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Other income totaled $43 million in 2008 and $69 million in 2007. The 2008 amount included $33 million in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. The 2007 amount included $36 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 $841 million in 2007. The 2008 amount included impairment charges of $501 million related to NO_x and SO₂ environmental allowances intangible assets 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 filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code. The 2007 amount included net charges of $755 million related to the cancelled development of eight coal-fueled generation units (see Note 4 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009). See Note 10 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for details of other income and deductions.

Interest expense and related charges increased $1.834 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 net gain related to interest rate swaps, partially offset by $150 million in increased capitalized interest. The increase was also net of $27 million in additional interest in the 2007 period attributable to the ten additional days in the period. See Note 25 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

Income tax benefit totaled $462 million in 2008 compared to income tax expense of $309 million in 2007. The 2007 amount includes a deferred tax benefit of $70 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 37.6% on income in 2007. (The deferred tax benefit in 2007 distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The decrease in the effective tax rate is driven by the effect of interest accrued for uncertain tax positions.

After-tax results declined $1.706 billion to a loss of $983 million in 2008.

• After-tax results in the Competitive Electric segment declined $1.584 billion to a loss of $862 million in 2008.

• Net income in the Regulated Delivery segment increased $44 million to $309 million in 2008.

• Corporate and Other net expenses totaled $430 million in 2008 and $288 million in 2007. The amounts in 2008 and 2007 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The increase of $142 million reflected:

o a $115 million increase in net interest expense, driven by issuance of Merger-related debt;

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

o a $38 million deferred tax benefit in 2007 related to the Texas margin tax, and

o a $15 million increase in SG&A expense as discussed above.

partially offset by:

o 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

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

Competitive Electric Segment

The following tables present financial operating results of the Competitive Electric segment for the Successor periods of the years ended December 31, 2009 and 2008, the three months ended December 31, 2008, the period from October 11, 2007 through December 31, 2007 and the nine months ended September 30, 2008, and for the Predecessor period from January 1, 2007 through October 10, 2007. Volumetric and other statistical data have been presented as of and for the Successor periods of the years ended December 31, 2009 and 2008, the three months ended December 31, 2008 and 2007 and the nine months ended December 31, 2008, and for the Predecessor period for the nine months ended September 30, 2007.

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Financial Results

	Successor															Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Three Months Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Nine Months Ended September 30, 2008			Period from January 1, 2007 through October 10, 2007
Operating revenues	$	7,911		$	9,787		$	1,979		$	1,671		$	7,809		$	6,884
Fuel, purchased power costs and delivery fees		(3,934	)		(5,600	)		(954	)		(852	)		(4,646	)		(3,209	)
Net gain (loss) from commodity hedging and trading activities		1,736			2,184			2,432			(1,492	)		(248	)		(554	)
Operating costs		(693	)		(677	)		(177	)		(124	)		(500	)		(471	)
Depreciation and amortization		(1,172	)		(1,092	)		(265	)		(315	)		(827	)		(253	)
Selling, general and administrative expenses		(741	)		(682	)		(183	)		(154	)		(499	)		(489	)
Franchise and revenue-based taxes		(108	)		(110	)		(36	)		(30	)		(74	)		(81	)
Impairment of goodwill		(70	)		(8,000	)		(8,000	)		—			—			—
Other income		59			34			26			2			8			22
Other deductions		(68	)		(1,274	)		(715	)		(8	)		(559	)		(735	)
Interest income		64			61			15			10			46			271
Interest expense and related charges		(1,946	)		(4,010	)		(2,187	)		(609	)		(1,824	)		(357	)
Income (loss) before income taxes		1,038			(9,379	)		(8,065	)		(1,901	)		(1,314	)		1,028
Income tax (expense) benefit		(407	)		450			(2	)		656			452			(306	)
Net income (loss)	$	631		$	(8,929	)	$	(8,067	)	$	(1,245	)	$	(862	)	$	722
Competitive Electric Segment
Sales Volume and Customer Count Data
	Successor												Successor			Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Three Months Ended December 31, 2008			Three Months Ended December 31, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Sales volumes:
Retail electricity sales volumes — (GWh):
Residential		28,046			28,135			5,982			5,967			22,153			21,256
Small business (a)		7,962			7,363			1,561			1,622			5,802			5,861
Large business and other customers		14,573			13,945			2,994			3,591			10,951			10,946
Total retail electricity		50,581			49,443			10,537			11,180			38,906			38,063
Wholesale electricity sales volumes		43,259			47,270			11,741			11,198			35,529			27,914

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	Successor												Successor			Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Three Months Ended December 31, 2008			Three Months Ended December 31, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Net sales (purchases) of balancing electricity to/from ERCOT		(939	)		(527	)		808			47			(1,335	)		622
Total sales volumes		92,901			96,186			23,086			22,425			73,100			66,599
Average volume (kWh) per residential customer (b)		14,855			14,780			3,101			3,197			11,767			11,399
Weather (North Texas average) — percent of normal (c):
Cooling degree days		98.9	%		108.5	%		101.3	%		171.8	%		109.0	%		94.2	%
Heating degree days		99.9	%		92.5	%		90.7	%		89.7	%		93.7	%		106.2	%
Customer counts:
Retail electricity customers (end of period and in thousands) (d):
Residential		1,862			1,914			1,914			1,857			1,909			1,839
Small business (a)		262			275			275			274			276			275
Large business and other customers		23			25			25			33			27			35
Total retail electricity customers		2,147			2,214			2,214			2,164			2,212			2,149

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

(b) Calculated using average number of customers for the 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). Normal is defined as the average over a 20-year period.

(d) Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number of meters does not reflect the number of individual customers. Each of the year ended December 31, 2008 and three months ended December 31, 2008 and 2007 amounts reflects reclassification of 18 thousand meters, and the nine months ended September 30, 2007 amounts reflect the reclassification of 19 thousand meters from residential to small business to conform to current presentation.

Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities

	Successor															Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Three Months Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Nine Months Ended September 30, 2008			Period from January 1, 2007 through October 10, 2007
Operating revenues:
Retail electricity revenues:
Residential	$	3,806		$	3,782		$	816		$	654		$	2,966		$	3,064
Small business (a)		1,164			1,099			247			202			852			880
Large business and other customers		1,261			1,447			304			286			1,143			1,070
Total retail electricity revenues		6,231			6,328			1,367			1,142			4,961			5,014
Wholesale electricity revenues (b)		1,463			3,329			532			505			2,797			1,637
Net sales (purchases) of balancing electricity to/from ERCOT		(80	)		(214	)		13			(9	)		(227	)		(14	)
Amortization of intangibles (c)		5			(36	)		(21	)		(50	)		(15	)		—

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	Successor															Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Three Months Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Nine Months Ended September 30, 2008			Period from January 1, 2007 through October 10, 2007
Other operating revenues		292			380			88			83			293			247
Total operating revenues	$	7,911		$	9,787		$	1,979		$	1,671		$	7,809		$	6,884
Net gain (loss) from commodity hedging and trading activities:
Unrealized net gains (losses) from changes in fair value	$	1,741		$	2,290		$	2,527		$	(1,469	)	$	(237	)	$	(646	)
Unrealized net gains (losses) representing reversals of previously recognized fair values of positions settled in the current period		(464	)		(9	)		59			(87	)		(68	)		(76	)
Realized net gains (losses) on settled positions		459			(97	)		(154	)		64			57			168
Total gain (loss)	$	1,736		$	2,184		$	2,432		$	(1,492	)	$	(248	)	$	(554	)

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

(b) Upon settlement of physical derivative power sales and purchase contracts that are marked-to-market in net income, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result, these line item amounts include a noncash component, which the company considers “unrealized.” These amounts are as follows:

	Successor													Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008		Three Months Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007		Nine Months Ended September 30, 2008			Period from January 1, 2007 through October 10, 2007
Reported in revenues	$	(166	)	$	42	$	(113	)	$	—	$	155		$	—
Reported in fuel and purchased power costs		114			6		77			—		(71	)		—
Net gain (loss)	$	(52	)	$	48	$	(36	)	$	—	$	84		$	—

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

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data

	Successor										Predecessor
	Year Ended December 31, 2009		Year Ended December 31, 2008		Three Months Ended December 31, 2008		Period from October 11, 2007 through December 31, 2007		Nine Months Ended September 30, 2008		Period from January 1, 2007 through October 10, 2007
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	114	$	95	$	26	$	21	$	69	$	66
Lignite/coal		670		640		155		127		485		467
Total baseload fuel		784		735		181		148		554		533
Natural gas fuel and purchased power (a)		1,224		2,881		349		302		2,532		1,435
Amortization of intangibles (b)		292		318		72		67		246		—
Other costs		202		351		47		68		304		213
Fuel and purchased power costs		2,502		4,285		649		585		3,636		2,181
Delivery fees (c)		1,432		1,315		305		267		1,010		1,028
Total	$	3,934	$	5,600	$	954	$	852	$	4,646	$	3,209

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	Successor															Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Three Months Ended December 31, 2008			Three Months Ended December 31, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	5.66		$	4.92		$	5.46		$	4.64		$	4.75		$	4.59
Lignite/coal (d)	$	16.47		$	15.80		$	15.68		$	13.48		$	15.83		$	14.31
Natural gas fuel and purchased power	$	43.10		$	81.99		$	46.63		$	60.04		$	91.55		$	62.29
Delivery fees per MWh	$	28.09		$	26.33		$	28.66		$	26.64		$	25.69		$	25.60
Production and purchased power volumes (GWh):
Nuclear		20,104			19,218			4,770			5,157			14,448			13,664
Lignite/coal		45,684			44,923			11,226			12,197			33,697			34,297
Total baseload generation		65,788			64,141			15,996			17,354			48,145			47,961
Natural gas-fueled generation		2,447			4,122			279			500			3,843			3,491
Purchased power		26,018			31,018			7,202			5,483			23,816			18,619
Total energy supply		94,253			99,281			23,477			23,337			75,804			70,071
Less line loss and power imbalances (e)		1,352			3,095			391			912			2,704			3,472
Net energy supply volumes		92,901			96,186			23,086			22,425			73,100			66,599
Baseload capacity factors:
Nuclear		100.0	%		95.2	%		94.0	%		101.6	%		95.6	%		90.8	%
Lignite/coal		86.5	%		87.6	%		86.3	%		94.5	%		87.7	%		89.7	%
Total baseload		90.3	%		89.8	%		88.5	%		96.5	%		89.9	%		90.0	%

(a) See note (b) on previous page.

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

(c) Includes delivery fee charges from Oncor that 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.

(e) Includes physical purchases and sales, the financial results of which are reported in commodity hedging and trading activities in the income statement.

Competitive Electric Segment — Financial Results — Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Operating revenues decreased $1.876 billion, or 19%, to $7.911 billion in 2009.

Wholesale electricity revenues decreased $1.866 billion, or 56%, to $1.463 billion in 2009 as compared to 2008 when wholesale revenues increased 55%. Volatility in wholesale revenues and purchased power costs reflects movements in natural gas prices, as lower natural gas prices in 2009 drove a 46% decline in average wholesale electricity sales prices. Reported wholesale revenues and purchased power costs also reflect changes in volumes of bilateral contracting activity entered into to mitigate the effects of demand volatility and congestion. Results in 2009 reflect lower demand volatility and a decline in congestion, which drove an 8% decline in wholesale sales volumes.

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Bilateral electricity contracting activity includes hedging transactions that utilize contracts for physical delivery. Wholesale sales and purchases of electricity are reported gross in the income statement if the transactions are scheduled for physical delivery with ERCOT.

Comparisons of wholesale balancing activity, reported net, 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. The activity in 2009 reflected reduced volatility and congestion, in part due to actions taken by ERCOT.

Retail electricity revenues declined $97 million, or 2%, to $6.231 billion and reflected the following:

• Lower average pricing contributed $242 million to the revenue decline. The change in average pricing reflected lower average contracted business rates driven by lower wholesale electricity prices, partially offset by higher average pricing in the residential and non-contract business markets resulting from advanced meter surcharges as well as customer mix.

• Retail sales volume growth of 2% increased revenues by $145 million. Volumes rose in the business markets driven by changes in customer mix resulting from contracting activity, but declined slightly in the residential market driven by a 3% decrease in customers.

Other operating revenues decreased $88 million, or 23%, to $292 million in 2009 due to lower natural gas prices and lower volumes on sales of natural gas to industrial customers.

The change in operating revenues also reflected a $41 million decrease in amortization of intangible assets arising from purchase accounting reflecting expiration of retail sales contracts.

Fuel, purchased power costs and delivery fees decreased $1.666 billion, or 30%, to $3.934 billion in 2009. This decrease was driven by lower purchased power costs due to the effect of lower natural gas prices, decreased demand volatility and reduced congestion as discussed above regarding wholesale revenues. Lower costs of replacement power during unplanned generation unit repair outages contributed to improved margin. Other factors contributing to lower fuel and purchased power costs included lower natural gas-fueled generation and lower related fuel costs ($374 million), the effect of lower natural gas prices on natural gas purchased for sale to industrial customers ($116 million) and lower amortization of intangible assets arising from purchase accounting ($26 million).

Overall baseload generation production increased 3% in 2009 reflecting a 5% increase in nuclear production and a 2% increase in lignite/coal-fueled production. The increase in nuclear production, which reflects two refueling outages in 2008 compared to one refueling outage in 2009 and investments to increase generation capacity, resulted in improved margin. The increase in lignite/coal-fueled production reflected generation from the new units placed in service in the fourth quarter 2009, partially offset by generation reductions during certain periods when power could be purchased in the wholesale market at prices below production costs, which was largely due to lower natural gas prices and higher wind generation availability.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the years ended December 31, 2009 and 2008, which totaled $1.736 billion and $2.184 billion in net gains, respectively:

Year Ended December 31, 2009 — Unrealized mark-to-market net gains totaling $1.277 billion included:

• $1.260 billion in net gains related to hedge positions, which includes $1.719 billion in net gains from changes in fair value, driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $459 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

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• $17 million in net gains related to trading positions, which includes $22 million in net gains from changes in fair value and $5 million in net losses that represent reversals of previously recorded net gains on positions settled in the period.

Realized net gains totaling $459 million included:

• $449 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

• $10 million in net gains related to trading positions.

Year Ended December 31, 2008— Unrealized mark-to-market net gains totaling $2.281 billion included:

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

• $68 million in “day one” net losses related to large hedge positions (see Note 18 to EFH Corp.��s historical consolidated financial statements for the year ended December 31, 2009), and

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

Realized net losses totaling $97 million included:

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

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

Unrealized gains and losses that are related to physically settled derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $52 million in net losses in 2009 and $48 million in net gains in 2008.

Operating costs increased $16 million, or 2%, to $693 million in 2009 driven by $28 million in costs related to the new lignite-fueled generation facilities. The change also reflected $19 million in higher maintenance costs incurred during planned and unplanned lignite-fueled generation unit outages in 2009 that was more than offset by the $31 million effect of two planned nuclear generation unit outages in 2008 as compared to one in 2009.

Depreciation and amortization increased $80 million, or 7%, to $1.172 billion in 2009. The increase was driven by $39 million in higher amortization expense related to the intangible asset representing retail customer relationships recorded in purchase accounting and $24 million due to the placement in service of two new generation units and related mining assets. Increased lignite generation unit depreciation as a result of normal capital additions as well as adjustments to useful lives of components was partially offset by lower natural gas generation unit depreciation resulting from an impairment in 2008.

SG&A expenses increased $59 million, or 9%, to $741 million in 2009. The increase reflected $36 million in higher retail bad debt expense, reflecting higher delinquencies due to delays in final bills and disconnects resulting from a system conversion, customer losses and general economic conditions. The increase also reflected higher employee related expenses, the implementation of a new retail customer information management system and the transition of certain previously outsourced customer operations, partially offset by $13 million in lower fees associated with the sale of receivables program.

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See Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of the impairments of goodwill of $70 million in 2009 and $8.0 billion in 2008.

Other income totaled $59 million in 2009 and $34 million in 2008. The 2009 amount included a $23 million reversal of a use tax accrual, an $11 million reversal of exit liabilities recorded in connection with the termination of outsourcing arrangements (see Notes 2 and 20 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009), a $6 million fee received related to an interest rate swap/commodity hedge derivative agreement, $5 million in royalty income and $5 million in sales/use tax refunds. The 2008 amount included an insurance recovery of $21 million and $4 million in royalty income. See Note 10 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for more details.

Other deductions totaled $68 million in 2009 and $1.274 billion in 2008. The 2009 amount included $34 million in charges for the impairment of land expected to be sold within the next 12 months, $7 million in charges for severance and other individually immaterial miscellaneous expenses. The 2008 amount included $501 million in impairment charges related to NO_x and SO₂ environmental allowances intangible assets and $481 million related to trade name intangible assets, both discussed in Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009, $229 million in impairment charges related to the natural gas-fueled generation facilities discussed in Note 5 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 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 filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code. See Note 10 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for more details.

Interest expense and related charges decreased $2.064 billion, or 51%, to $1.946 billion in 2009. The decrease reflected a $696 million unrealized mark-to-market net gain related to interest rate swaps in 2009 compared to a $1.477 billion net loss in 2008, partially offset by $118 million in increased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges in August 2008.

Income tax expense totaled $407 million in 2009 compared to an income tax benefit totaling $450 million in 2008. Excluding the impacts of the goodwill impairment of $70 million in 2009 and $8.0 billion in 2008, the effective income tax rate was 36.7% in 2009 and 32.6% in 2008. (These nondeductible charges distort the comparison; therefore, they have been excluded for purposes of a more meaningful discussion.) The increase in the rate reflects the effect of interest accrued for uncertain tax positions, which increased the rate on income in 2009 and decreased the rate on a loss in 2008.

After-tax results for the segment improved $9.560 billion to net income of $631 million in 2009, reflecting the 2008 impairment of goodwill, the 2008 impairment charges reported in other deductions and the change in unrealized mark-to-market values of interest rate swaps reported in interest expense, partially offset by lower net gains from commodity hedging and trading activities driven by lower unrealized mark-to-market net gains.

Competitive Electric Segment — Financial Results — Three Months Ended December 31, 2008 Compared to Successor Period from October 11, 2007 through December 31, 2007

Operating revenues increased $308 million, or 18%, to $1.979 billion in 2008.

Retail electricity revenues increased $225 million, or 20%, to $1.367 billion in 2008 and reflected the following:

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

• Higher average pricing in all markets contributed to the revenue increase, with residential rates increasing an average of 7%, and higher average rates in the business markets reflecting a change in customer mix in the large business market.

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• The effect of higher retail pricing was partially offset by the effect of a 6% decline in total retail sales volumes driven by the business markets. The lower sales volumes in the business markets reflected a decline in commercial and industrial activity due to economic conditions.

• Total retail electricity customer counts at December 31, 2008 increased 2% from December 31, 2007, driven by a 3% increase in residential customers.

Wholesale electricity revenues increased $27 million, or 5%, to $532 million in 2008. The increase in wholesale electricity revenues reflected $66 million in revenues attributable to the ten fewer days in the 2007 period. The change also reflected lower wholesale electricity prices driven by lower natural gas prices.

The change in operating revenues also reflected a $29 million decrease in amortization of intangible assets arising in purchase accounting.

Fuel, purchased power costs and delivery fees increased $102 million, or 12%, to $954 million in 2008. The increase was largely due to $123 million in costs attributable to the ten fewer days in the 2007 period.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the three months ended December 31, 2008 and the Successor period from October 11, 2007 through December 31, 2007:

Three Months Ended December 31, 2008— Net gain totaling $2.432 billion included:

• Unrealized mark-to-market net gains of $2.586 billion, substantially all of which related to commodity hedge positions and

• Realized net losses totaling $154 million, including $101 million in net losses related to commodity hedge positions that primarily offset hedged electricity revenues recognized in the period and $53 million in net losses related to trading positions.

Period from October 11 through December 31, 2007— Net losses totaling $1.492 billion included:

• Unrealized mark-to-market net losses of $1.556 billion, substantially all of which related to commodity hedge positions and

• Realized net gains totaling $64 million consisting primarily of net gains related to commodity hedge positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the period.

Operating costs increased $53 million, or 43%, to $177 million in 2008. The increase was partially due to $19 million in costs attributable to the ten fewer days in the 2007 period. The increase in operating costs also reflects higher maintenance costs related to the timing and scope of planned and unplanned outages in baseload generation facilities, higher staffing and benefits costs and expenses associated with operational readiness of the generation units under construction.

Depreciation and amortization decreased $50 million, or 16%, to $265 million in 2008. The decrease in depreciation and amortization reflected lower amortization expense related to the intangible value of customer relationships, partially offset by incremental depreciation expense from stepped-up property, plant and equipment values, both related to purchase accounting and $8 million in expense attributable to the ten fewer days in the 2007 period.

SG&A expenses increased $29 million, or 19%, to $183 million in 2008. The increase was partially due to $15 million in expenses attributable to the ten fewer days in the 2007 period. The increase in SG&A expenses also reflected higher bad debt expense due in part to the effects of Hurricane Ike and higher salaries and contractor costs to support customer growth initiatives and computer system enhancements, net of a decrease in fees associated with the sale of accounts receivable program and lower advertising-related costs.

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See Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of the $8.0 billion goodwill impairment charge recorded in the fourth quarter of 2008.

Other income totaled $26 million in 2008 and $2 million in 2007. Other income in 2008 included a $21 million insurance recovery for damages to certain mining equipment. Other deductions totaled $715 million in 2008 and $8 million in 2007. Other deductions in 2008 included a charge of $481 million for the impairment of a trade name intangible asset (see Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009) and a $229 million charge to write down the natural gas-fueled generation facilities to fair value (see Note 5 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009).

Interest income increased $5 million to $15 million in 2008 reflecting higher average balances of notes/advances to parent.

Interest expense and related charges increased $1.578 billion to $2.187 billion in 2008. The increase was driven by an unrealized mark-to-market net loss on interest rate swaps of $1.512 billion.

Income tax expense on a pre-tax loss for 2008 totaled $2 million compared to a $656 million income tax benefit on a pre-tax loss in 2007. Excluding the impact of the $8.0 billion goodwill impairment in 2008, the effective rate on a pre-tax loss was 3.1% in 2008 compared to 34.5% in 2007. (This nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The decrease in the rate is driven by the unfavorable impact of tax provision adjustments recorded in 2008 on a small pre-tax loss.

After-tax results for the segment declined by $6.822 billion to a loss of $8.067 billion driven by impairment charges related to goodwill, the trade name intangible asset and the natural gas-fueled generation facilities and the unrealized mark-to-market net losses on interest rate swaps, partially offset by the change in unrealized mark-to-market values of commodity hedge positions in the long-term hedging program.

Competitive Electric Segment — Financial Results — Nine Months Ended September 30, 2008 Compared to Predecessor Period from January 1, 2007 through October 10, 2007

Operating revenues increased $925 million, or 13%, to $7.809 billion in 2008.

Wholesale electricity revenues increased $1.160 billion, or 71%. 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 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. The increase in wholesale electricity revenues and sales volumes was partially offset by $66 million in revenues attributable to the ten additional days in the 2007 period.

The $53 million, or 1%, decrease in retail electricity revenues reflected the following:

• The ten additional days in the 2007 period contributed $186 million to the decrease in retail electricity revenues.

• The decrease in retail electricity revenues was partially offset by a 2% increase in retail sales volumes that increased revenues by $107 million. Residential volumes increased 4% reflecting the effects of warmer than normal weather in 2008 combined with the cooler than normal weather experienced in 2007 and a 4% increase in residential customer counts. Business and other customer volumes were comparable with 2007.

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• The decrease in retail electricity revenues was also partially offset by higher average pricing that 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 6% price discount in March 2007, an additional 4% price discount in June 2007 and another 5% price discount in October 2007 to those residential customers in Oncor’s service territory with month-to-month service plans and a rate equivalent to the former price-to-beat.

Comparisons of wholesale balancing activity, reported net, 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. The relatively large amount in 2008 reflects weather-driven volatility, generation facility outages and congestion effects.

Other operating revenues increased $46 million, or 19%, to $293 million primarily due to higher retail natural gas revenues reflecting increased prices, the effect of which was partially offset by $11 million in revenues attributable to the ten additional days in the 2007 period.

Fuel, purchased power costs and delivery fees increased $1.437 billion, or 45%, 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. The increase in fuel, purchased power costs and delivery fees was partially offset by $123 million in costs attributable to the ten additional days in the 2007 period.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the nine months ended September 30, 2008 and the Predecessor period from January 1, 2007 through October 10, 2007, which totaled $248 million and $554 million in net losses, respectively:

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 18 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009), 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.

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

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• $566 million in net losses related to hedge positions, which includes $528 million in net losses from changes in fair value and $38 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;

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

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

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

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

Realized net gains totaling $168 million include:

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

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

Operating costs increased $29 million, or 6%, 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 our own benefit, $10 million in higher property taxes and $5 million of expenses associated with operational readiness of the generation units under construction, partially offset by $7 million in costs in 2007 for utilization of SO₂credits for the lignite/coal-fueled generation plants and $3 million in individually insignificant items. The increase in operating costs was partially offset by $19 million in costs attributable to the ten additional days in the 2007 period.

Depreciation and amortization increased $574 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, both resulting from the effects of purchase accounting. The remaining increase primarily reflects normal additions and replacements of equipment in generation operations. The increase in depreciation and amortization was partially offset by $8 million in costs attributable to the ten additional days in the 2007 period.

SG&A expenses increased $10 million, or 2%, 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

• $15 million in expenses attributable to the ten additional days in the 2007 period, and

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

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Other income totaled $8 million in 2008 and $22 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 income totaling $3 million in 2007 was attributable to the ten additional days in the period.

Other deductions totaled $559 million in 2008 and $735 million in 2007. The 2008 amount includes $501 million in impairment charges related to NO_x and SO₂ environmental allowances intangible assets discussed in Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 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 we had ceased operating for our own benefit and a $10 million charge related to the termination of a railcar operating lease. See Note 10 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for more details.

Interest income decreased $225 million, or 83%, to $46 million in 2008 reflecting lower average balances of notes/advances to parent. The ten additional days in the 2007 period contributed $11 million to the decrease.

Interest expense and related charges increased $1.467 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, 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. The increase was also net of $15 million in additional interest in the 2007 period attributable to the ten additional days in the period.

Income tax benefit on a pretax loss totaled $452 million in 2008 and income tax expense on pretax income totaled $306 million in 2007. The 2007 amount includes a deferred tax benefit of $32 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 32.9% on income in 2007. (The deferred tax benefit in 2007 distorts the comparison; therefore it has been excluded for purposes of a more meaningful discussion.) The increase in the effective tax rate is due to a lower lignite depletion benefit in 2008, partially offset by the effect of the Texas margin tax under which interest expense is not deductible.

Net income (loss) decreased $1.584 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

The following tables present financial operating results of the Regulated Delivery segment for the Successor periods of the years ended December 31, 2009 and 2008, the three months ended December 31, 2008, the period from October 11, 2007 through December 31, 2007 and the nine months ended September 30, 2008, and for the Predecessor period from January 1, 2007 through October 10, 2007. Volumetric and other statistical data have been presented as of and for the Successor periods of the years ended December 31, 2009 and 2008, the three months ended December 31, 2008 and 2007 and the nine months ended December 31, 2008, and for the Predecessor period for the nine months ended September 30, 2007.

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Financial Results

	Successor															Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Three Months Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Nine Months Ended September 30, 2008			Period from January 1, 2007 through October 10, 2007
Operating revenues	$	2,690		$	2,580		$	612		$	532		$	1,969		$	1,987
Operating costs		(908	)		(828	)		(208	)		(182	)		(620	)		(637	)
Depreciation and amortization		(557	)		(492	)		(122	)		(96	)		(370	)		(366	)
Selling, general and administrative expenses		(194	)		(164	)		(38	)		(45	)		(126	)		(139	)
Franchise and revenue-based taxes		(250	)		(255	)		(69	)		(62	)		(186	)		(198	)
Impairment of goodwill		—			(860	)		(860	)		—			—			—
Other income		49			45			11			11			34			3
Other deductions		(34	)		(19	)		(2	)		(7	)		(17	)		(27	)
Interest income		43			45			11			12			34			44
Interest expense and related charges		(346	)		(317	)		(89	)		(70	)		(229	)		(242	)
Income (loss) before income taxes		493			(265	)		(754	)		93			489			425
Income tax expense (a)		(173	)		(221	)		(41	)		(30	)		(180	)		(160	)
Net income (loss)	$	320		$	(486	)	$	(795	)	$	63		$	309		$	265

(a) Effective with the sale of noncontrolling interests (see Note 15 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009), Oncor is taxed as a partnership and thus not subject to income taxes; however, subsequent to the sale, Oncor reflects a “provision in lieu of income taxes,” and the results of segments are evaluated as if they file their own income tax returns.

Operating Data

	Successor								Successor		Predecessor
	Year Ended December 31, 2009		Year Ended December 31, 2008		Three Months Ended December 31, 2008		Three Months Ended December 31, 2007		Nine Months Ended September 30, 2008		Nine Months Ended September 30, 2007
Operating statistics — volumes:
Electric energy billed volumes (GWh)		103,376		107,828		23,969		25,784		83,859		79,645
Reliability statistics (a):
System Average Interruption Duration Index (SAIDI) (nonstorm)		84.5		85.4		85.4		77.9		82.6		79.2
System Average Interruption Frequency Index (SAIFI) (nonstorm)		1.1		1.1		1.1		1.1		1.1		1.1
Customer Average Interruption Duration Index (CAIDI) (nonstorm)		77.2		74.7		74.7		70.6		75.3		69.5
Electric points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters)		3,145		3,123		3,123		3,093		3,116		3,087

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	Successor										Predecessor
	Year Ended December 31, 2009		Year Ended December 31, 2008		Three Months Ended December 31, 2008		Period from October 11, 2007 through December 31, 2007		Nine Months Ended September 30, 2008		Period from January 1, 2007 through October 10, 2007
Operating revenues:
Electricity distribution revenues (b):
Affiliated (TCEH)	$	1,017	$	998	$	226	$	208	$	773	$	821
Nonaffiliated		1,339		1,264		304		257		960		921
Total distribution revenues		2,356		2,262		530		465		1,733		1,742
Third-party transmission revenues		299		280		73		60		207		199
Other miscellaneous revenues		35		38		9		7		29		46
Total operating revenues	$	2,690	$	2,580	$	612	$	532	$	1,969	$	1,987

(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 $147 million and $140 million for the years ended December 31, 2009 and 2008, respectively; $32 million for the three months ended December 31, 2008; $29 million for the period October 11, 2007 through December 31, 2007; $108 million for the nine months ended September 30, 2008 and $116 million for the period January 1, 2007 through October 10, 2007. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs.

Regulated Delivery Segment — Financial Results — Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Operating revenues increased $110 million, or 4%, to $2.690 billion in 2009. The increase reflected:

• $55 million from increased distribution tariffs, including the August 2009 rate review order;

• $28 million from a surcharge to recover advanced metering deployment costs and $11 million from a surcharge to recover additional energy efficiency costs, both of which became effective with the January 2009 billing cycle;

• $20 million in higher transmission revenues reflecting rate increases to recover ongoing investment in the transmission system;

• an estimated $14 million impact from growth in points of delivery;

• $9 million performance bonus for meeting PUCT energy efficiency targets, and

• $7 million in higher charges to REPs related to transition bonds (with an offsetting increase in amortization of the related regulatory asset),

partially offset by an estimated $27 million in lower average consumption primarily due to the effects of milder weather and general economic conditions and $7 million due to less requested REP discretionary and third-party maintenance services.

Operating costs increased $80 million, or 10%, to $908 million in 2009. The increase reflected $45 million in higher fees paid to other transmission entities, $21 million in additional expense recognition as a result of the PUCT’s August 2009 final order in the rate review (see discussion immediately below) and $10 million in costs related to programs designed to improve customer electricity demand efficiency, the majority of which are reflected in the revenue increases discussed above.

Under accounting rules for rate regulated utilities, certain costs are deferred as regulatory assets (see Note 25 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009) when incurred and are recognized as expense when recovery of the costs are allowed in revenue under regulatory approvals. Accordingly, beginning in September 2009, the effective date of the new tariffs resulting from the rate review (see “Regulation and Rates” below), Oncor began to amortize as operating costs or SG&A expenses certain costs previously deferred as regulatory assets over the recoverability period under the rate review order and recognized higher costs related to the current period. The additional expense recognized included $14 million related to storm recovery costs and $10 million related to pension and OPEB costs (including $3 million reported in SG&A expense).

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Depreciation and amortization increased $65 million, or 13%, to $557 million in 2009. The increase reflected $34 million in higher depreciation due to ongoing investments in property, plant and equipment (including $11 million related to advanced meters), $24 million due to increased depreciation and amortization rates implemented upon the PUCT approval of new tariffs in September 2009 and $7 million in higher amortization of regulatory assets associated with securitization bonds (with an offsetting increase in revenues).

SG&A expenses increased $30 million, or 18%, to $194 million in 2009. The increase reflected $12 million related to advanced meters and $3 million in additional expense recognition as a result of the PUCT’s final order in the rate review, both of which have related revenue increases, $8 million in higher professional and contractor fees driven by outsourcing transition and CREZ development activities and $6 million in higher costs related to employee benefit plans, partially offset by a $3 million one-time reversal of bad debt expense due to the PUCT’s finalization of the Certification of Retail Electric Providers rule in April 2009. Write-offs of uncollectible amounts owed by nonaffiliated REPs are deferred as a regulatory asset (see “Regulation and Rates”).

Taxes other than amounts related to income taxes decreased $5 million, or 2%, to $250 million in 2009 reflecting a decrease in local franchise fees due to decreased volumes of electricity delivered.

See Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for a discussion of the $860 million goodwill impairment charge recorded in 2008.

Other income totaled $49 million in 2009 and $45 million in 2008. The 2009 and 2008 amounts included accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting totaling $39 million and $44 million, respectively. The 2009 amount also included $10 million due to the reversal of exit liabilities recorded in purchase accounting related to the termination of outsourcing arrangements. See Note 2 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

Other deductions totaled $34 million in 2009 and $19 million in 2008. The 2009 amount included a $25 million write off of regulatory assets (see Note 25 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009). The 2009 and 2008 amounts included costs totaling $2 million and $13 million, respectively, associated with the 2006 rate settlement with certain cities.

Interest income decreased $2 million, or 4%, to $43 million in 2009. The decrease reflected $4 million in lower reimbursement of transition bond interest from TCEH due to lower remaining principal amounts of the bonds and $2 million in lower interest income on temporary cash investments and restricted cash due to lower interest rates, partially offset by $4 million in higher earnings on investments held for certain employee benefit plans.

Interest expense and related charges increased $29 million, or 9%, to $346 million in 2009. The increase reflected $17 million in higher average borrowings, reflecting ongoing capital investments. The increase also reflected $12 million due to higher average interest rates, which was driven by refinancing of short-term borrowings with $1.5 billion of senior secured notes issued in September 2008. The majority of the proceeds of the September 2008 notes issuance was used to pay outstanding short-term borrowings under Oncor’s credit facility.

Income tax expense totaled $173 million in 2009 compared to $221 million in 2008. The effective rate decreased to 35.1% in 2009 from 37.2% in 2008, excluding the impact of the $860 million goodwill impairment in 2008. (This nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The decrease in the rate was driven by the reversal of accrued interest due to the favorable resolution of uncertain tax positions.

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Net income for 2009 totaled $320 million and net loss for 2008 totaled $486 million. The change reflects the $860 million goodwill impairment charge recorded in 2008, as well as $53 million in lower results in 2009 driven by the effect of lower average consumption on revenues, the write-off of certain regulatory assets and increased interest expense.

Regulated Delivery Segment — Financial Results — Three Months Ended December 31, 2008 Compared to Successor Period from October 11, 2007 through December 31, 2007

Operating revenues increased $80 million, or 15%, to $612 million in 2008. The increase is largely due to $68 million in revenues attributable to the ten fewer days in the 2007 period. The increase also reflected increased distribution tariffs to recover transmission costs, the impact of growth in points of delivery and higher transmission revenues primarily due to a rate increase to recover ongoing investment in the transmission system, partially offset by lower average consumption due to the effects of milder weather.

Operating costs increased $26 million, or 14%, to $208 million in 2008. The increase is largely due to $21 million in costs attributable to the ten fewer days in the 2007 period. The increase also reflected higher property taxes and higher fees paid to other transmission entities, partially offset by lower vegetation management expenses.

Depreciation and amortization increased $26 million, or 27%, to $122 million in 2008. The increase included $12 million in costs attributable to the ten fewer days in the 2007 period. The remaining increase largely reflected higher depreciation due to ongoing investments in property, plant and equipment.

SG&A expenses decreased $7 million, or 16%, to $38 million in 2008. The decrease reflected lower incentive compensation expense and decreased employee benefit costs, partially offset by $2 million in costs attributable to the ten fewer days in the 2007 period.

Franchise and revenue-based taxes increased $7 million, or 11%, to $69 million in 2008. The increase is largely due to the ten fewer days in the 2007 period.

See Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for a discussion of the $860 million goodwill impairment charge recorded in 2008.

Other income totaled $11 million in both 2008 and 2007. The amounts reflected accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting. Other deductions totaled $2 million and $7 million in 2008 and 2007, respectively. The 2007 amount included costs associated with the 2006 rate settlement with certain cities totaling $6 million.

Interest income decreased $1 million, or 8%, to $11 million in 2008. The decrease reflected lower earnings on investments held for certain employee benefit plans, partially offset by $2 million in interest income attributable to the ten fewer days in the 2007 period.

Interest expense and related charges increased by $19 million, or 27%, to $89 million in 2008. The increase included $9 million in costs attributable to the ten fewer days in the 2007 period. The remaining increase reflected $7 million from higher average borrowings, reflecting ongoing capital investments, and $1 million from higher average interest rates.

Income tax expense totaled $41 million in 2008 compared to $30 million in 2007. The effective income tax rate increased to 38.7% in 2008, excluding the impact of the $860 million goodwill impairment charge, from 32.3% in 2007. (This nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The increase in the effective rate was driven by the impact of higher Texas margin tax due in part to the effects of the tax sharing agreement in 2007 and higher accrued interest related to uncertain tax positions.

Net loss for 2008 totaled $795 million and net income for 2007 totaled $63 million. The change was driven by the $860 million goodwill impairment charge recorded in 2008.

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Regulated Delivery Segment — Financial Results — Nine Months Ended September 30, 2008 Compared to Predecessor Period from January 1, 2007 through October 10, 2007

Operating revenues decreased $18 million, or less than 1%, to $1.969 billion in 2008. The decreased revenue reflected:

• $68 million attributable to the ten additional days in the 2007 period;

• $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 securitization bonds (with an offsetting decrease in amortization of the related regulatory asset),

partially offset by:

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

• an estimated $16 million impact from 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 pole contact revenues.

Operating costs decreased $17 million, or 3%, to $620 million in 2008. The decrease reflected:

• $21 million attributable to the ten additional days in the 2007 period, and

• $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,

partially offset by:

• $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 broadband over power line (BPL) based “Smart Grid” network in May 2008.

Depreciation and amortization increased $4 million, or 1%, 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 securitization bonds (with an offsetting decrease in revenues) and $12 million attributable to the ten additional days in the 2007 period.

SG&A expenses decreased $13 million, or 9%, to $126 million in 2008. The decrease reflected:

• $7 million in lower incentive compensation expense;

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• $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;

• $2 million attributable to the ten additional days in the 2007 period, 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.

Franchise and revenue-based taxes decreased $12 million, or 6%, to $186 million in 2008. Of the decrease, $8 million was attributable to the ten additional days in the 2007 period. 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 for the nine months ended September 30, 2008 and $5 million for the period from January 1, 2007 through October 10, 2007.

Other income totaled $34 million in 2008 and $3 million in 2007. The 2008 amount reflected accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting.

Other deductions totaled $17 million in 2008 and $27 million in 2007. The 2008 amount includes:

• $13 million in costs as a result of the 2006 settlement with certain cities related to rates, and

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

The 2007 amount includes:

• $20 million in costs a result of the 2006 cities rate settlement;

• $3 million in costs related to a cancelled joint venture arrangement, and

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

Interest income decreased $10 million, or 23%, to $34 million in 2008. The decrease reflected $4 million in lower earnings on assets held for certain employee benefit plans, a $3 million decrease in reimbursement of transition bond interest from TCEH and $2 million attributable to the ten additional days in the 2007 period.

Interest expense decreased $13 million, or 5%, to $229 million in 2008. The decrease reflected $9 million attributable to the ten additional days in the 2007 period.

Income tax expense totaled $180 million in 2008 compared to $160 million in 2007. The effective income tax rate decreased to 36.8% in 2008 from 37.6% in 2007. The decrease in the effective rate was primarily driven by a decrease in the benefit from the Medicare subsidy for post-employment benefits.

Net income increased $44 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 periods presented. The net changes in these assets and liabilities, excluding “fair value adjustments,” “other activity” and “reclassification” as described below, represent the pretax effect on earnings of positions in the commodity contract portfolio that are marked-to-market in net income (see Note 18 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009). The portfolio consists primarily of economic hedges but also includes trading positions.

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	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			October 11, 2007 through December 31, 2007			January 1, 2007 through October 10, 2007
Commodity contract net asset (liability) at beginning of period	$	430		$	(1,917	)	$	(920	)	$	(23	)
Settlements of positions (a)		(518	)		39			(87	)		(55	)
Changes in fair value (b)		1,741			2,294			(1,469	)		(757	)
Fair value adjustments at Merger closing date (c)		—			—			144			—
Reclassification at Merger closing date (d)		—			—			400			—
Other activity (e)		65			14			15			(85	)
Commodity contract net asset (liability) at end of period (f)	$	1,718		$	430		$	(1,917	)	$	(920	)

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

(b) Represents unrealized gains and losses recognized, primarily related to positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”). Includes gains and losses recorded at contract inception dates (see Note 18 to the Financial Statements).

(c) Represents purchase accounting adjustments arising primarily from the adoption of fair value accounting (largely nonperformance risk effect).

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

(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, generally related to options purchased/sold and physical natural gas exchange transactions. Activity in 2009 included $36 million for the net payment of option premiums, $29 million in natural gas provided under physical gas exchange transactions and $18 million in amortization of derivative liabilities related to settlement of certain multi-year power sales agreements (see Note 18 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009), partially offset by $18 million for expired option premiums. Activity in the 2007 Predecessor period included $257 million (net of amounts settled of $7 million) in liabilities related to certain power sales agreements, net of a $102 million payment related to a structured economic hedge transaction in the long-term hedging program and $64 million in natural gas provided under physical gas exchange transactions.

(f) 2009 amount excludes $4 million in net derivative liabilities related to cash flow hedge positions not marked-to-market in net income.

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 18 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009). The total pretax effect of recording unrealized gains and losses in net income related to commodity contracts is summarized as follows:

	Successor								Predecessor
	Year Ended December 31, 2009		Year Ended December 31, 2008			October 11, 2007 through December 31, 2007			January 1, 2007 through October 10, 2007
Unrealized gains (losses) related to contracts marked-to-market	$	1,223	$	2,333		$	(1,556	)	$	(812	)
Ineffectiveness gains (losses) related to cash flow hedges		2		(4	)		—			90
Total unrealized gains (losses) related to commodity contracts	$	1,225	$	2,329		$	(1,556	)	$	(722	)

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Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of December 31, 2009, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

	Maturity dates of unrealized commodity contract asset as of December 31, 2009
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(63	)	$	(92	)	$	—		$	—		$	(155	)
Prices provided by other external sources		745			904			143			—			1,792
Prices based on models		39			(7	)		227			(178	)		81
Total	$	721		$	805		$	370		$	(178	)	$	1,718
Percentage of total fair value		42	%		47	%		21	%		(10	)%		100	%

The “prices actively quoted” category reflects only exchange traded contracts for which active quotes are readily available. The “prices provided by other external sources” category represents forward commodity positions valued using prices for which over-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT that are deemed active markets (excluding the West zone) 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 proprietary long-term pricing models that utilize certain market based inputs. See Note 16 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for fair value disclosures and discussion of fair value measurements.

COMPREHENSIVE INCOME

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

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Net increase (decrease) in fair value of cash flow hedges:
Commodities	$	(20	)	$	(8	)	$	5		$	(288	)
Financing — interest rate swaps		—			(175	)		(182	)		—
		(20	)		(183	)		(177	)		(288	)
Derivative value net losses (gains) reported in net income that relate to hedged transactions recognized in the period:
Commodities		11			11			—			(95	)
Financing — interest rate swaps		119			111			—			6
		130			122			—			(89	)
Total income (loss) effect of cash flow hedges reported in other comprehensive income	$	110		$	(61	)	$	(177	)	$	(377	)

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.

We have historically used, and expect 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 the value of dedesignated and terminated cash flow hedges at the time of such dedesignation/termination, 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 18 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

133

FINANCIAL CONDITION

Liquidity and Capital Resources

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

	Successor															Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Three Months Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Nine Months Ended September 30, 2008			Period from January 1, 2007 through October 10, 2007
Cash flows — operating activities
Income (loss) from continuing operations	$	408		$	(9,998	)	$	(9,015	)	$	(1,361	)	$	(983	)	$	699
Adjustments to reconcile income (loss) from continuing operations to cash provided by (used in) operating activities:
Depreciation and amortization		2,172			2,070			516			568			1,554			684
Deferred income tax expense (benefit) — net		253			(477	)		(44	)		(736	)		(433	)		(111	)
Impairment charges		124			10,071			9,570			—			501			—
Increase of toggle notes in lieu of cash interest		511			—			—			—			—			—
Net charges related to cancelled development of generation facilities		—			—			—			2			—			676
Unrealized net (gains) losses from mark-to-market valuations of commodity positions		(1,225	)		(2,329	)		(2,550	)		1,556			221			722
Unrealized net (gains) losses from mark-to-market valuations of interest rate swaps		(696	)		1,477			1,512			—			(36	)		—
Other, net		196			182			55			16			128			52
Changes in operating assets and liabilities (including margin deposits)		(32	)		509			504			(495	)		5			(457	)
Cash provided by (used in) operating activities	$	1,711		$	1,505		$	548		$	(450	)	$	957		$	2,265
Cash flows — financing activities
Equity financing from Sponsor Group and other investors	$	—		$	—		$	—		$	8,236		$	—		$	—
Net issuances, repayments and repurchases of borrowings		458			1,537			(1,468	)		26,615			3,005			2,304
Net proceeds from sale of noncontrolling interests		—			1,253			1,253			—			—			—
Common stock dividends paid		—			—			—			—			—			(788	)
Debt discount, financing and reacquisition expenses		(49	)		(21	)		(2	)		(986	)		(19	)		(17	)
Other, net		13			68			2			—			66			(105	)
Cash provided by (used in) financing activities	$	422		$	2,837		$	(215	)	$	33,865		$	3,052		$	1,394
Cash flows — investing activities
Acquisition of EFH Corp.	$	—		$	—		$	—		$	(32,694	)	$	—		$	—
Capital expenditures, including purchases of mining-related assets and nuclear fuel		(2,545	)		(3,015	)		(810	)		(716	)		(2,205	)		(2,542	)
Investment posted with derivative counterparty		(400	)		—			—			—			—			—
Reduction of (proceeds from) TCEH senior secured letter of credit facility deposited with bank		115			—			—			(1,250	)		—			—
Other, net		197			81			250			97			(169	)		259
Cash used in investing activities	$	(2,633	)	$	(2,934	)	$	(560	)	$	(34,563	)	$	(2,374	)	$	(2,283	)

134

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 —Cash provided by operating activities totaled $1.711 billion in 2009 compared to $1.505 billion in 2008. The $206 million increase reflected:

• a $489 million decrease in cash interest paid due to the payment of approximately $465 million of interest with an increase in toggle notes instead of cash as discussed under “Toggle Notes Interest Election” below, and

• a $57 million favorable impact of timing of advanced metering surcharges,

partially offset by a $347 million decrease in net margin deposits received primarily due to the effects of forward natural gas prices on positions in the long-term hedging program.

Three Months Ended December 31, 2008 Compared to Successor Period from October 11, 2007 through December 31, 2007 — Cash provided by operating activities totaled $548 million in the three months ended December 31, 2008 compared to cash used in operating activities of $450 million in the Successor period from October 11, 2007 through December 31, 2007. The $998 million increase reflects a $1.445 billion favorable change in net margin deposits primarily due to the effect of lower forward natural gas prices on positions in the long-term hedging program and a $143 million favorable change in income taxes paid due to a refund received in 2008, partially offset by a $737 million increase in cash interest payments.

Nine Months Ended September 30, 2008 Compared to Predecessor Period from January 1, 2007 through October 10, 2007— Cash provided by operating activities totaled $957 million in the nine months ended September 30, 2008 compared to $2.265 billion in the Predecessor period from January 1, 2007 through October 10, 2007. The $1.308 billion decrease reflected a $1.588 billion increase in cash interest payments, partially offset by a $333 million favorable change in margin deposits primarily due to the effect of lower forward natural gas prices on hedge positions.

The decline in capital spending for the year ended December 31, 2009 as compared to the year ended December 31, 2008 primarily reflected a decrease in spending related to the construction of new generation facilities, which is nearing completion, partially offset by capital expenditures in the regulated business for advanced metering deployment and CREZ. Capital expenditures in 2009 totaled $1.324 billion in the Competitive Electric segment and $998 million in the Regulated Delivery segment.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $418 million, $460 million, $123 million, $153 million, $337 million and $50 million for the years ended December 31, 2009 and December 31, 2008, the three months ended December 31, 2008, the period from October 11, 2007 through December 31, 2007, the nine months ended September 30, 2008 and the Predecessor period from January 1, 2007 through October 10, 2007, respectively. For the 2007 Predecessor period, this difference represented amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent with industry practice. For the 2009, 2008 and 2007 Successor periods, this difference also represented 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, other income and interest expense.

135

Debt Financing Activity—Activities related to short-term borrowings and long-term debt during the year ended December 31, 2009 are as follows (all amounts presented are principal, and repayments and repurchases, including exchanges, include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):

	Borrowings (a)		Repayments and Repurchases (b)
TCEH	$	739	$	415
EFCH		—		7
EFIH		141		—
EFH Corp.		424		227
Oncor		—		104
Total long-term		1,304		753
TCEH		53		—
Oncor		279		—
Total short-term (c)		332		—
Total	$	1,636	$	753

(a) Includes $782 million of noncash principal increases consisting of: $309 million of EFH Corp. Toggle Notes and $202 million of TCEH Toggle Notes in May and November 2009 in payment of accrued interest as discussed below under “Toggle Notes Interest Election,” $256 million of EFH Corp. and EFIH notes issued in debt exchanges as discussed in Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 and $15 million related to capital leases.

(b) Includes $357 million of noncash retirements as a result of debt exchanges discussed in Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

(c) Short-term amounts represent net borrowings/repayments.

See Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for further detail of long-term debt and other financing arrangements.

We, our affiliates or our agents may from time to time purchase our outstanding debt securities for cash in open market purchases or privately negotiated transactions or pursuant to a Section 10b-5(1) plan, or we may refinance existing debt securities. We will evaluate any such transactions in light of market prices of the securities, taking into account 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. See Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of debt exchange offers completed in November 2009.

Available Liquidity — The following table summarizes changes in available liquidity for the year ended December 31, 2009.

	Available Liquidity
	December 31, 2009		December 31, 2008		Change
Cash and cash equivalents, excluding Oncor	$	1,161	$	1,564	$	(403	)
Investments held in money market fund		—		142		(142	)
TCEH Delayed Draw Term Loan Facility		—		522		(522	)
TCEH Revolving Credit Facility (a)		1,721		1,767		(46	)
TCEH Letter of Credit Facility		399		490		(91	)
Subtotal	$	3,281	$	4,485	$	(1,204	)
Short-term investment (b)		490		—		490
Total liquidity, excluding Oncor (c)	$	3,771	$	4,485	$	(714	)
Cash and cash equivalents — Oncor	$	28	$	125	$	(97	)
Oncor Revolving Credit Facility		1,262		1,508		(246	)
Total Oncor liquidity	$	1,290	$	1,633	$	(343	)

136

(a) As of December 31, 2009 and 2008, the TCEH Revolving Credit Facility includes $141 million and $144 million, respectively, of commitments from Lehman that are only available from the fronting banks and the swingline lender.

(b) Includes $425 million cash investment (including accrued interest) and $65 million in letters of credit posted related to certain interest rate and commodity hedge transactions. Under the related agreement, the collateral is to be returned no later than March 2010. See Note 18 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

(c) Pursuant to PUCT rules, TCEH is required to maintain available liquidity to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at December 31, 2009, the total availability under the TCEH credit facilities should be further reduced by $228 million. See “Regulation and Rates — Certification of REPs.”

Note: Available liquidity above does not include the amounts available from exercising the payment-in-kind (PIK) option on the EFH Corp. Toggle Notes and TCEH Toggle Notes, which for the remaining payment dates from May 2010 through November 2012 could avoid cash interest payments of approximately $1.6 billion.

The $714 million decrease in available liquidity excluding Oncor, after taking into account the short-term investment, was driven by capital spending to construct the new generation facilities.

The decrease in available liquidity for Oncor of $343 million in the year ended December 31, 2009 reflected ongoing capital investment in transmission and distribution infrastructure.

See Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for additional discussion of these credit facilities.

The net proceeds from the January 2010 issuance of $500 million principal amount of senior secured notes (described in Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009) increased available liquidity.

Pension and OPEB Plan Funding— Pension and OPEB plan funding is expected to total $45 million and $24 million, respectively, in 2010. Based on the funded status of the pension plan at December 31, 2009, funding is expected to total approximately $750 million for the 2010 to 2014 period. Oncor is expected to fund approximately 75% of this amount consistent with its share of the pension liability. We made pension and OPEB contributions of $109 million and $22 million, respectively, in 2009 including transfers of investments related to the salary deferral and supplemental retirement plans totaling $31 million.

See Note 21 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for more information regarding the pension and OPEB plans, including the funded status of the plans as of December 31, 2009.

Toggle Notes Interest Election — EFH Corp. and TCEH have the option every six months at their discretion, ending with the payment due November 2012, to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments. We elected to do so for the May 2009, November 2009 and May 2010 interest payments as an efficient and cost-effective method to further enhance liquidity, in light of the weaker economy and related lower electricity demand and the continuing uncertainty in the financial markets. Once EFH Corp. and/or TCEH make a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. and/or TCEH revoke the applicable election. Use of the PIK feature will be evaluated at each election period, taking into account market conditions and other relevant factors at such time.

EFH Corp. made its May and November 2009 interest payments and will make its May 2010 interest payment by using the PIK feature of the its Toggle Notes. During the applicable interest periods, the interest rate on the notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the notes by $150 million and $159 million in May and November 2009, respectively, and will further increase the aggregate principal amount of the notes by $168 million in May 2010. The elections increased liquidity in 2009 by an amount equal to approximately $290 million and will further increase liquidity in May 2010 by an amount equal to approximately $157 million, with such amounts constituting the amount of cash interest that otherwise would have been payable on the notes. If paid in cash, the annual interest expense would increase by approximately $54 million, constituting the additional cash interest that would be payable with respect to the $477 million of additional principal amount. See Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of debt exchange offers that resulted in redemption of portions of the outstanding principal of these notes.

137

Similarly, TCEH made its May and November 2009 interest payments and will make its May 2010 interest payment by using the PIK feature of the its Toggle Notes. During the applicable interest periods, the interest rate on the notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the notes by approximately $98.5 million and $104 million in May and November 2009, respectively, and will further increase the aggregate principal amount of the notes by approximately $110 million in May 2010. The elections increased liquidity in 2009 by an amount equal to approximately $189 million and will further increase liquidity in May 2010 by an amount equal to approximately $103 million, with such amounts constituting the amount of cash interest that otherwise would have been payable on the notes. If paid in cash, the annual interest expense would increase by approximately $33 million, constituting the additional interest that would be payable with respect to the $312 million of additional principal amount.

Liquidity Needs, Including Capital Expenditures — Capital expenditures, including capitalized interest, for 2010 are expected to total approximately $1.950 billion and include:

• $1.0 billion for investment in Oncor’s transmission and distribution infrastructure, including $216 million for Oncor’s investment related to the CREZ Transmission Plan;

• $900 million for investments in TCEH generation facilities, including approximately:

• $700 million for major maintenance, primarily in existing generation operations;

• $150 million related to completion of the construction of a second generation unit and mine development at Oak Grove, and

• $50 million for environmental expenditures related to existing generation units, and

• $50 million for information technology and other corporate investments.

We expect cash flows from operations combined with availability under our credit facilities discussed in Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 to provide sufficient liquidity to fund our current obligations, projected working capital requirements, any restructuring obligations and capital spending for a period that includes the next twelve months.

Liquidity Effects of Commodity Hedging and Trading Activities — Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other forms of credit support to satisfy such collateral obligations. In addition, TCEH’s Commodity Collateral Posting Facility, an uncapped senior secured revolving 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 December 31, 2009, more than 95% of the long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral requirements for those hedging transactions. See Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for more information about this facility.

138

As of December 31, 2009, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $183 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $317 million posted as of December 31, 2008;

• $516 million in cash has been received from counterparties, net of $4 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $402 million received, net of $122 million in cash posted, as of December 31, 2008;

• $379 million in letters of credit have been posted with counterparties, as compared to $342 million posted as of December 31, 2008, and

• $44 million in letters of credit have been received from counterparties, as compared to $30 million received as of December 31, 2008.

In addition, EFH Corp. (parent) elected to post cash collateral of $400 million in 2009 related to certain TCEH interest rate and commodity hedge transactions (see Note 18 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009).

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 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. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing liquidity in the event that it was not restricted. As of December 31, 2009, restricted cash collateral held totaled $1 million. See Note 25 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 regarding restricted cash.

With the long-term hedging program, increases in natural gas prices generally result in increased cash collateral and letter of credit postings to counterparties. As of December 31, 2009, approximately 600 million MMBtu of positions related to the long-term hedging program were not directly secured on an asset-lien basis and thus have cash collateral posting requirements. The uncapped TCEH Commodity Collateral Posting Facility supports the collateral posting requirements related to these transactions.

Interest Rate Swap Transactions — See Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for TCEH interest rate swaps entered into as of December 31, 2009.

Distributions from Oncor — Until December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor’s net income determined in accordance with GAAP, subject to certain defined adjustments. Distributions are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.

In January 2009, the PUCT awarded approximately $1.3 billion of Competitive Renewable Energy Zone (CREZ) construction projects to Oncor. See discussion below under “Regulation and Rates — Oncor Matters with the PUCT.” As a result of the increased capital expenditures for CREZ and the debt-to-equity ratio cap, we expect that Oncor may retain all or a portion of its available cash to fund such construction instead of paying distributions.

139

Income Tax Refunds/Payments — Income tax payments, primarily amounts related to the Texas margin tax, are expected to total approximately $75 million in the next 12 months. In 2009, we received a refund totaling $98 million in income taxes and related interest related to IRS audits of 1993 and 1994 income tax returns and made net payments totaling approximately $44 million related to the Texas margin tax. In 2008, we received net federal income tax refunds of $229 million, including $98 million related to 2007 tax payments and $142 million related to a net operating loss carryback to the 2006 tax year. Federal income tax payments totaled $257 million in 2007.

As discussed in Note 8 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009, we assess uncertain tax positions under a “more-likely-than-not” standard. We cannot reasonably estimate the ultimate amounts and timing of tax payments associated with uncertain tax positions, but expect that no material federal income tax payments related to such positions will be made in 2010.

Sale of Accounts Receivable — TXU Energy participates in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with transfers and servicing accounting standards. Under the program, TXU Energy (originator) sells retail trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp., which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions. All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $383 million and $416 million at December 31, 2009 and 2008, respectively. See Note 1 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of a new accounting standard that is expected to require consolidation of this program and Note 11 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for a more complete description of the program including the impact of the program on the financial statements for the periods presented and the contingencies that could result in termination of the program and a reduction of liquidity should the underlying financing be settled.

Capitalization — Our capitalization ratios consisted of 104.6% and 106.0% long-term debt, less amounts due currently, and (4.6)% and (6.0)% common stock equity, at December 31, 2009 and 2008, respectively. Total debt to capitalization, including short-term debt, was 104.4% and 105.8% at December 31, 2009 and 2008, respectively.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain of our financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of December 31, 2009, we were in compliance with all such maintenance covenants.

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

Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. Senior Notes) for the year ended December 31, 2009 totaled $4.857 billion for EFH Corp. The following are reconciliations of net income to Adjusted EBITDA for EFH Corp. and TCEH, respectively, for the years ended December 31, 2009 and 2008.

140

EFH Corp. Consolidated

Adjusted EBITDA Reconciliation

	Year Ended December 31, 2009			Year Ended December 31, 2008
	(millions of dollars)
Net income (loss) attributable to EFH Corp.	$	344		$	(9,838	)
Income tax expense (benefit)		367			(471	)
Interest expense and related charges		2,912			4,935
Depreciation and amortization		1,754			1,610
EBITDA	$	5,377		$	(3,764	)
Oncor EBITDA		(1,354	)		(496	)
Oncor distributions/dividends (a)		216			1,582
Interest income		(45	)		(27	)
Amortization of nuclear fuel		95			76
Purchase accounting adjustments (b)		346			460
Impairment of goodwill		90			8,000
Impairment of assets and inventory write down (c)		42			1,221
Net gain on debt exchange offers		(87	)		—
Net income (loss) attributable to noncontrolling interests		64			(160	)
EBITDA amount attributable to consolidated unrestricted subsidiaries		3			—
Unrealized net (gain) loss resulting from hedging transactions		(1,225	)		(2,329	)
Amortization of “day one” net loss on Sandow 5 power purchase agreement		(10	)		—
Losses on sale of receivables		12			29
Noncash compensation expenses (d)		11			27
Severance expense (e)		10			3
Transition and business optimization costs (f)		22			45
Transaction and merger expenses (g)		81			64
Insurance settlement proceeds (h)		—			(21	)
Restructuring and other (i)		(14	)		35
Expenses incurred to upgrade or expand a generation station (j)		100			100
Adjusted EBITDA per Incurrence Covenant	$	3,734		$	4,845
Add back Oncor adjustments	$	1,123		$	(267	)
Adjusted EBITDA per Restricted Payments Covenants	$	4,857		$	4,578

(a) 2008 amount includes $1.253 billion distribution of net proceeds from the sale of Oncor noncontrolling interests.

(b) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits not recognized in net income due to purchase accounting.

(c) Impairment of assets includes impairments of emission allowances and trade name intangible assets, impairments of land and the natural gas-fueled generation fleet and charges related to the cancelled development of coal-fueled generation facilities.

(d) Noncash compensation expenses are accounted for under accounting standards related to stock compensation and exclude capitalized amounts.

(e) Severance expense includes amounts incurred related to outsourcing, restructuring and other amounts deemed to be in excess of normal recurring amounts.

(f) Transition and business optimization costs include professional fees primarily for retail billing and customer care systems enhancements and incentive compensation.

(g) Transaction and merger expenses include costs related to the Merger and abandoned strategic transactions, outsourcing transition costs, administrative costs related to the cancelled program to develop coal-fueled generation facilities, the Sponsor Group management fee, costs related to certain growth initiatives and costs related to the Oncor sale of noncontrolling interests.

(h) Insurance settlement proceeds include the amount received for property damage to certain mining equipment.

(i) Restructuring and other for 2009 primarily represents reversal of certain liabilities accrued in purchase accounting and recorded as other income, partially offset by restructuring and nonrecurring activities; 2008 includes a litigation accrual, a charge related to the bankruptcy of a subsidiary of Lehman Brothers Holdings Inc., and other restructuring initiatives and nonrecurring activities.

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

141

TCEH Consolidated

Adjusted EBITDA Reconciliation

	Year Ended December 31, 2009			Year Ended December 31, 2008
	(millions of dollars)
Net income (loss)	$	709		$	(8,862	)
Income tax expense (benefit)		447			(411	)
Interest expense and related charges		1,833			3,918
Depreciation and amortization		1,172			1,092
EBITDA	$	4,161		$	(4,263	)
Interest income		(64	)		(60	)
Amortization of nuclear fuel		95			76
Purchase accounting adjustments (a)		299			413
Impairment of goodwill		70			8,000
Impairment of assets and inventory write down (b)		36			1,210
EBITDA amount attributable to consolidated unrestricted subsidiaries		3			—
Unrealized net (gain) loss resulting from hedging transactions		(1,225	)		(2,329	)
Amortization of “day one” net loss on Sandow 5 power purchase agreement		(10	)		—
Corporate depreciation, interest and income tax expenses included in SG&A expense		6			—
Losses on sale of receivables		12			29
Noncash compensation expense (c)		1			10
Severance expense (d)		10			3
Transition and business optimization costs (e)		25			33
Transaction and merger expenses (f)		5			10
Insurance settlement proceeds (g)		—			(21	)
Restructuring and other (h)		(19	)		31
Expenses incurred to upgrade or expand a generation station (i)		100			100
Adjusted EBITDA per Incurrence Covenant	$	3,505		$	3,242
Expenses related to unplanned generation station outages (i)		91			250
Other adjustments allowed to determine Adjusted EBITDA per Maintenance Covenant (j)		38			15
Adjusted EBITDA per Maintenance Covenant	$	3,634		$	3,507

(a) Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits not recognized in net income due to purchase accounting.

(b) Impairment of assets includes impairments of emission allowances and trade name intangible assets and impairments of land and the natural gas-fueled generation fleet.

(c) Noncash compensation expenses are accounted for under accounting standards related to stock compensation and 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, outsourcing transition costs and costs related to certain growth initiatives.

(g) Insurance settlement proceeds include the amount received for property damage to certain mining equipment.

(h) Restructuring and other for 2009 primarily represents reversal of certain liabilities accrued in purchase accounting and recorded as other income, partially offset by restructuring and nonrecurring activities; 2008 includes a charge related to the bankruptcy of a subsidiary of Lehman Brothers Holdings Inc. and other restructuring initiatives and nonrecurring activities.

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

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

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The following table summarizes TCEH’s secured debt to adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp., EFIH and TCEH that are applicable under certain other covenants in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the EFH Corp. Senior Notes, the EFH Corp. 9.75% Notes and the EFIH Notes as of December 31, 2009 and 2008 and the corresponding maintenance and other covenant threshold levels as of December 31, 2009:

	December 31, 2009	December 31, 2008	Threshold Level as of December 31, 2009
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to adjusted EBITDA ratio	4.76 to 1.00	4.77 to 1.00	Must not exceed 7.25 to 1.00 (a)
Debt Incurrence Covenants:
EFH Corp. Senior Notes:
EFH Corp. fixed charge coverage ratio	1.2 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
TCEH fixed charge coverage ratio	1.5 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
EFH Corp. 9.75% Notes:
EFH Corp. fixed charge coverage ratio	1.2 to 1.0	N/A	At least 2.0 to 1.0
TCEH fixed charge coverage ratio	1.5 to 1.0	N/A	At least 2.0 to 1.0
EFIH Notes:
EFIH fixed charge coverage ratio (b)	53.8 to 1.0	N/A	At least 2.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio	1.5 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio	1.5 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
Restricted Payments/Limitations on Investments Covenants:
EFH Corp. Senior Notes:
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (c)	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (c)	1.2 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
EFH Corp. leverage ratio	9.4 to 1.0	6.9 to 1.0	Equal to or less than 7.0 to 1.0
EFH Corp. 9.75% Notes:
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (c)	1.4 to 1.0	N/A	At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (c)	1.2 to 1.0	N/A	At least 2.0 to 1.0
EFH Corp. leverage ratio	9.4 to 1.0	N/A	Equal to or less than 7.0 to 1.0
EFIH Notes:
General restrictions (non-EFH Corp. payments):
EFIH fixed charge coverage ratio (b) (d)	3.9 to 1.0	N/A	At least 2.0 to 1.0
General restrictions (EFH Corp. payments):
EFIH fixed charge coverage ratio (b) (d)	53.8 to 1.0	N/A	At least 2.0 to 1.0
EFIH leverage ratio	4.4 to 1.0	N/A	Equal to or less than 6.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio	1.5 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
Payments to Sponsor Group:
TCEH total debt to adjusted EBITDA ratio	8.4 to 1.0	8.7 to 1.0	At least 6.5 to 1.0

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(a) Threshold level decreases to a maximum of 7.00 to 1.00 effective March 31, 2010 and to a maximum of 6.75 to 1.00 effective December 31, 2010. Calculation excludes debt that ranks junior to the TCEH Senior Secured Facilities.

(b) Although EFIH currently meets the fixed charge coverage ratio threshold applicable to certain covenants contained in the indenture governing the EFIH Notes, EFIH’s ability to use such thresholds to incur debt or make restricted payments/investments is currently limited by the covenants contained in the EFH Corp. Senior Notes and the EFH Corp. 9.75% Notes.

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

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

Material Credit Rating Covenants and Credit Worthiness Effects on Liquidity — As a result of TCEH’s non-investment grade credit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, as of December 31, 2009, counterparties to those contracts could have required TCEH to post up to an aggregate of $41 million in additional collateral. This amount largely represents the below market terms of these contracts as of December 31, 2009; thus, this amount will vary depending on the value of these contracts on any given day.

Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. As of December 31, 2009, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $29 million, with $15 million of this amount posted for the benefit of Oncor.

The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of December 31, 2009, TCEH maintained availability under its credit facilities of approximately $228 million. See “Regulation and Rates — Certification of REPs.”

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 (a subsidiary of TCEH) is not sufficient to support its 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. The actual amount (if required) could 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 $43 million as of December 31, 2009 (which is subject to weekly adjustments based on settlement activity with ERCOT).

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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 its payment obligations to Oncor if two or more rating agencies downgrade Oncor’s credit ratings below investment grade.

Other arrangements of EFH Corp. and its subsidiaries, including Oncor’s credit facility, the accounts receivable securitization program (see Note 11 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the relevant credit ratings.

In the event that any or all of the additional collateral requirements discussed above are triggered, we believe we 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 of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to the sale of receivables program and hedging obligations, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity of outstanding balances ($22.357 billion at December 31, 2009) under such facilities.

The indenture governing the TCEH Senior 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 or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the TCEH Senior Notes.

Under the terms of a TCEH rail car lease, which had approximately $47 million in remaining lease payments as of December 31, 2009 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

Under the terms of a TCEH rail car lease, which had approximately $53 million in remaining lease payments as of December 31, 2009 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

The indentures governing the EFH Corp. Senior Notes, 9.75% and 10% Notes contain a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of EFH Corp. or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the EFH Corp. Senior Notes, 9.75% and 10% Notes.

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

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

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We enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which vary, stated in the contracts. The subsidiaries whose default would trigger cross default vary depending on the contract.

Each of TCEH’s natural gas hedging agreements that are secured with a lien on its assets on a pari passu basis with the TCEH Senior Secured Facilities contains a cross default provision. In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but ranging from $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedging agreements would have the right to terminate its hedge 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 an aggregate derivative liability of $1.21 billion at December 31, 2009 would have the right to terminate its interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.

A default by Oncor or any subsidiary thereof in respect of indebtedness in a principal amount in excess of $50 million may result in a cross default under its credit facility. Under this facility such a default may cause the maturity of outstanding balances ($616 million at December 31, 2009) under such facility to be accelerated.

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

Long-Term Contractual Obligations and Commitments — The following table summarizes our contractual cash obligations as of December 31, 2009 (see Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for additional disclosures regarding these long-term debt and noncancellable purchase obligations).

Contractual Cash Obligations	Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years		Total
Long-term debt — principal (a)	$	340	$	1,820	$	22,817	$	17,492	$	42,469
Long-term debt — interest (b)		3,059		6,491		5,747		7,115		22,412
Operating and capital leases (c)		146		149		114		330		739
Obligations under commodity purchase and services agreements (d)		1,595		1,796		954		815		5,160
Total contractual cash obligations	$	5,140	$	10,256	$	29,632	$	25,752	$	70,780

(a) Excludes capital lease obligations, unamortized discounts and fair value premiums and discounts related to purchase accounting. Also excludes $278 million of additional principal amount of notes to be issued in May 2010 and due in 2016 and 2017, reflecting the election of the PIK feature on toggle notes as discussed above under “Toggle Notes Interest Election.”

(b) Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interest rate swaps are calculated based on interest rates in effect at December 31, 2009.

(c) Includes short-term noncancellable leases.

(d) Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments. Amounts presented for variable priced contracts assumed the year-end 2009 price remained in effect for all periods except where contractual price adjustment or index-based prices were specified.

The following are not included in the table above:

• contracts between affiliated entities and intercompany debt;

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

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

• employment contracts with management;

• estimated funding of pension plan totaling $45 million in 2010 and approximately $750 million for the 2010 to 2014 period as discussed above under “Pension and OPEB Plan Funding;”

• liabilities related to uncertain tax positions totaling $1.6 billion discussed in Note 8 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 as the ultimate timing of payment is not known; and

• capital expenditures under PUCT orders (advanced meters and CREZ projects).

Guarantees — See Note 13 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for details of guarantees.

OFF–BALANCE SHEET ARRANGEMENTS

See discussion above regarding sales of accounts receivable under “Financial Condition – Liquidity and Capital Resources” and in Note 11 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

Also see Note 13 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 regarding guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 13 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

See Note 1 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for a discussion of changes in accounting standards.

REGULATION AND RATES

Regulatory Investigations and Reviews

See Note 13 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

Certification of REPs

In April 2009, the PUCT finalized a rule relating to the Certification of Retail Electric Providers. The rule strengthens the certification requirements for REPs in order to better protect customers, transmission and distribution utilities (TDUs), and other REPs from the potential insolvency of REPs. The rule, among other things, increases creditworthiness and financial reporting requirements for REPs and provides additional customer protection requirements and regulatory asset consideration for TDU bad debt expenses. Under the rule, Oncor uncollectible amounts owed by REPs are deferred as a regulatory asset. Recovery of the regulatory asset will be considered in a future rate case. Accordingly, Oncor recognized an approximately $3 million one-time reversal of bad debt expense in the three months ended June 30, 2009 (reported in other income). Due to the commitments made to the PUCT in connection with the Merger, Oncor may not recover bad debt expense, or certain other costs and expenses, from rate payers in the event of a TXU Energy default or bankruptcy. Under the rule, REPs are required to amend their certifications, including the manner in which they meet financial requirements, by May 21, 2010. TXU Energy plans to file its amended certification no later than the first quarter 2010. Under the new financial requirements, which will be effective upon approval of the amended certification, the amount of available liquidity required to be maintained by TCEH would have been reduced from $228 million as of December 31, 2009 to approximately $83 million as a result of no longer having to reserve liquidity for payments related to TDUs.

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FERC Infrastructure Protection Standards

In September 2009, the FERC issued an order approving a revised set of mandatory NERC standards for critical infrastructure protection (CIP). These standards are designed to protect the nation’s bulk power system against potential disruptions from cyber security breaches. The mandatory reliability standards require certain users, owners and operators of the bulk power system to establish policies, plans and procedures to safeguard physical and electronic access to control systems, to train personnel on security matters, to report security incidents, and to be prepared to recover from a cyber incident. Both Oncor and Luminant were compliant at December 31, 2009 and are expected to achieve “Auditable Compliance” by year-end 2010 in accordance with the NERC CIP implementation schedule.

Wholesale Market Design — Nodal Market

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

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

• operate a voluntary day-ahead energy market;

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

• use nodal energy prices for resources;

• provide information for energy trading hubs by aggregating nodes;

• use zonal prices for loads; and

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

ERCOT currently has a zonal wholesale market structure consisting of four geographic zones. The proposed location-based congestion-management market is referred to as a “nodal” market because wholesale pricing would differ across the various nodes on the transmission grid. The implementation of a nodal market is being done in conjunction with transmission improvements designed to reduce current congestion. Pursuant to a request from the PUCT, ERCOT announced in November 2008 a preliminary schedule for the implementation of the nodal market by December 2010.

ERCOT imposes a surcharge 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. In November 2008, ERCOT filed a request with the PUCT for approval of an interim increase in the nodal surcharge from $0.169 per MWh to $0.375 per MWh. In September 2009, the PUCT approved an increase in the nodal surcharge to $0.375 per MWh, effective January 1, 2010. At the approved $0.375 per MWh nodal surcharge, the annual surcharge to us will be an estimated $30 million to $35 million, which is reported in fuel, purchased power costs and delivery fees. The implementation of a nodal market is scheduled for December 2010. We cannot predict the ultimate impact of the proposed nodal wholesale market design on our operations or financial results.

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Environmental Regulations

See discussion in Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 regarding the invalidation of the EPA’s Clean Air Interstate Rule and the related impairment in 2008 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, which became final in June 2008, approving the terms of a stipulation relating to the filing in 2007 by Oncor and Texas Holdings of a Merger-related Joint Report and Application with the PUCT pursuant to Section 14.101(b) of PURA and PUCT Substantive Rule 25.75. The stipulation required the filing of a rate case by Oncor no later than July 1, 2008 based on a test year ended December 31, 2007. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200^th District Court of Travis County, Texas. The parties to the appeal have agreed to a schedule that would result in a hearing in June 2010. Oncor was named a defendant and intends to vigorously defend the appeal. Oncor filed the rate case with the PUCT in June 2008, and the PUCT issued a final order with respect to the rate review in August 2009 as discussed below.

Rate Case — In June 2008, Oncor filed for a rate review with the PUCT and 204 cities. In August 2009, the PUCT issued a final order with respect to the rate review. The final order approves a total annual revenue requirement for Oncor of $2.64 billion, based on Oncor’s 2007 test year cost of service and customer characteristics. New rates were calculated for all customer classes using 2007 test year billing metrics and the approved class cost allocation and rate design. The PUCT staff has estimated that the final order results in an approximate $115 million increase in base rate revenues over Oncor’s 2007 adjusted test year revenues, before recovery of rate case expenses. Prior to implementing the new rates in September 2009, Oncor had already begun recovering $45 million of the $115 million increase as a result of approved transmission cost recovery factor and energy efficiency cost recovery factor filings, such as those discussed below. Also see Note 25 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 regarding the PUCT’s review of regulatory assets and liabilities.

Key findings made by the PUCT in the rate review include:

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

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

• denying recovery of $25 million of regulatory assets, which resulted in a $16 million after tax loss being recognized in the three months ended September 30, 2009, and

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

New rates were implemented upon approval of new tariffs in September 2009. In November 2009, the PUCT issued an Order on Rehearing that established a new rate class but did not change the revenue requirements. In January 2010, the PUCT denied all Second Motions for Rehearing, which made the November 2009 Order on Rehearing final and appealable.

Advanced Meter Rulemaking — In 2005, the Texas Legislature passed legislation that authorized electric utilities to implement a surcharge to recover costs incurred in deploying advanced metering and meter information networks. Benefits of the advanced metering installation include improved safety, on-demand meter reading, enhanced outage identification and restoration and system monitoring of voltages. In 2007, the PUCT issued its advanced metering rule to implement this legislation. This rule outlined the minimum required functionality for an electric utility’s advanced metering systems to qualify for cost recovery under a surcharge. Subsequent to the issuance of the rule, the PUCT opened an implementation proceeding for market participants to fine-tune the rule requirements, address the impacts of advanced metering deployment on retail and wholesale markets in ERCOT, and help ensure that retail customers receive benefits from advanced metering deployment. The implementation proceeding is expected to continue through the end of 2010.

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Advanced Metering Deployment Surcharge Filing— In May 2008, Oncor filed with the PUCT a description and request for approval of its proposed advanced metering system deployment plan and its proposed surcharge for the recovery of its estimated future investment for advanced metering deployment. Oncor’s plan provides for the full deployment of over three million advanced meters by the end of 2012 to all residential and most non-residential retail electricity customers in Oncor’s service area. As of December 31, 2009, Oncor has installed approximately 660 thousand advanced digital meters, including 620 thousand in the year ended December 31, 2009. Cumulative capital expenditures for the deployment of the advanced meter system totaled $196 million as of December 31, 2009, including $166 million in the year ended December 31, 2009.

In August 2008, a settlement was reached with the majority of the parties to this surcharge filing. The settlement included the following major provisions, as amended by the final order in the 2008 rate review:

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

• a total revenue requirement over the surcharge period of $1.023 billion;

• estimated capital expenditures for advanced metering facilities of $686 million;

• related operation and maintenance expenses for the surcharge period of $153 million;

• $204 million of operation and maintenance expense savings; and

• an advanced metering cost recovery factor of $2.19 per month per residential retail customer and varying from $2.39 to $5.15 per month for non-residential retail customers.

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

Transmission Rates — In order to recover increases in its transmission costs, including incremental fees paid to other transmission service providers due to an increase in their rates, 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 2010, an application was filed to increase the TCRF, which is expected to be administratively approved and become effective in March 2010. This application is expected to increase annualized revenues by $13 million.

In September 2009, Oncor filed an application for an interim update of its wholesale transmission rate, and the PUCT approved the new rate effective December 2009. Accordingly, annualized revenues are expected to increase by approximately $34 million. Approximately $21 million of this increase is recoverable through transmission rates charged to wholesale customers, and the remaining $13 million is recoverable from REPs through the TCRF component of Oncor’s delivery rates.

Application for 2010 Energy Efficiency Cost Recovery Factor — In May 2009, Oncor filed an application with the PUCT to request approval of an energy efficiency cost recovery factor (EECRF) for 2010. PUCT rules require Oncor to make an annual EECRF filing by May 1 for implementation at the beginning of the next calendar year. The requested 2010 EECRF is $54 million, the same amount established for 2009, and would result in the same $0.92 per month charge for residential customers as proposed in Oncor’s rate case. As allowed by the rule, the 2010 EECRF is designed to recover the costs of the 2010 programs, the under-recovery of 2008 program costs, and a performance bonus based on 2008 results. In its November 2009 order, the PUCT approved the application with minor modifications, resulting in an immediate recognition of $9 million in revenues, representing the performance bonus. The final order resulted in a residential EECRF of $0.89 per month due to the PUCT approval of a different allocation methodology for the performance bonus. Oncor’s new EECRF rider became effective for billings on and after December 30, 2009.

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Competitive Renewable Energy Zones (CREZs) — In January 2009, the PUCT awarded approximately $1.3 billion of CREZ construction projects to Oncor. The projects involve the construction of transmission lines to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of the state. A written order reflecting the PUCT’s decision was entered in March 2009, and an order on rehearing was issued by the PUCT in May 2009. The cost estimates for the CREZ construction projects are based upon cost analyses prepared by ERCOT in April 2008. For the year ended December 31, 2009, Oncor’s CREZ-related capital expenditures totaled $114 million. It is expected that the necessary permitting actions and other requirements and all construction activities for Oncor’s CREZ construction projects will be completed by the end of 2013.

In October 2009, the PUCT initiated a proceeding to determine whether there is sufficient financial commitment from generators of renewable energy to grant Certificates of Convenience and Necessity (CCNs) for transmission facilities located in two areas in the panhandle of Texas designated as CREZs. If the PUCT determines that there is not sufficient financial commitment from the generators for either CREZ, the PUCT may take action, including delaying the filing of CREZ CCN applications until such time as the PUCT finds sufficient financial commitment for that CREZ in accordance with the financial commitment provisions of the PUCT’s rules. Three of the CREZ transmission projects awarded to Oncor are located in the two CREZs that are the subject of the proceeding. The estimated cost of these three transmission projects is approximately $380 million. The PUCT held a hearing in this proceeding in January 2010. Oncor expects the PUCT to issue an order concluding this proceeding in the second quarter of 2010.

In July 2009, the City of Garland, Texas filed an Original Petition and Application for Stay and Injunction in the 200^th District Court of Travis County, Texas seeking judicial review and a stay of the PUCT’s March 2009 written order selecting transmission service providers (including Oncor) to build CREZ transmission facilities. In January 2010, the district court issued an order reversing the PUCT’s order and remanding it to the PUCT for action consistent with the court’s opinion. The district court order did not contain a stay or injunction and severed the City of Garland’s requests for declaratory and injunctive relief. On February 4, 2010, the PUCT issued an order that severs certain of the CREZ transmission projects awarded to Oncor and others from its consideration of the remand of the written order. On February 12, 2010, the PUCT issued an order suspending the schedule sequencing CREZ projects subsequent to CREZ priority projects. In the original sequencing order, Oncor was scheduled to file CCN applications for its five CREZ subsequent projects between March and May 2010. The PUCT’s order stated that the record evidence regarding the selection of the transmission service providers for the CREZ subsequent projects will be reevaluated without delay. Oncor cannot predict the impact, if any, the reevaluation may have on its CREZ construction projects.

Sunset Review

PURA, the PUCT and the RRC will be subject to “sunset” review by the Texas Legislature in the 2011 legislative session. Sunset review includes, generally, a comprehensive review of the need for and effectiveness of an administrative agency (the PUCT or the RRC), along with an evaluation of the advisability of any changes to the PUCT’s authorizing legislation (PURA). A Sunset staff report is scheduled to be issued in April 2010, and a Sunset public meeting is scheduled for May 2010. We cannot predict the outcome of the Sunset review process.

Summary

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

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

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

Commodity Price Risk

TCEH is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. The company actively manages its portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. The company, 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, TCEH enters into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. The company continuously monitors the valuation of identified risks and adjusts positions based on current market conditions. The company strives to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

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

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

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

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

	Year Ended December 31, 2009		Year Ended December 31, 2008
Month-end average Trading VaR:	$	4	$	6
Month-end high Trading VaR:	$	7	$	15
Month-end low Trading VaR:	$	2	$	2

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

	Year Ended December 31, 2009		Year Ended December 31, 2008
Month-end average MtM VaR:	$	1,050	$	2,290
Month-end high MtM VaR:	$	1,470	$	3,549
Month-end low MtM VaR:	$	638	$	1,087

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

	Year Ended December 31, 2009		Year Ended December 31, 2008
Month-end average EaR:	$	1,088	$	2,300
Month-end high EaR:	$	1,511	$	3,916
Month-end low EaR:	$	676	$	1,069

The decreases in the risk measures (MtM VaR and EaR) above were primarily driven by lower natural gas prices in 2009.

Interest Rate Risk

The table below provides information concerning our financial instruments as of December 31, 2009 and 2008 that are sensitive to changes in interest rates, which include debt obligations and interest rate swaps. We have entered into interest rate swaps under which we have exchanged 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 under our credit facilities. In addition, in connection with entering into certain interest rate basis swaps to further reduce fixed borrowing costs, TCEH has changed the variable interest rate terms of certain debt from three-month LIBOR to one-month LIBOR, as discussed in Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009. 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 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for a discussion of changes in debt obligations.

	Expected Maturity Date																		Successor
	(millions of dollars, except percentages)
	2010			2011			2012			2013			2014			There- After			2009 Total Carrying Amount			2009 Total Fair Value		2008 Total Carrying Amount			2008 Total Fair Value
Long-term debt (including current maturities):
Fixed rate debt amount (a)	$	135		$	559		$	851		$	866		$	1,163		$	17,287		$	20,861		$	17,296	$	20,646		$	14,266
Average interest rate		5.46	%		5.66	%		6.24	%		6.00	%		5.57	%		9.59	%		8.95	%				8.70	%
Variable rate debt amount	$	205		$	205		$	205		$	205		$	20,583		$	205		$	21,608		$	17,463	$	21,261		$	14,886
Average interest rate		3.74	%		3.74	%		3.74	%		3.74	%		3.74	%		0.29	%		3.71	%				5.28	%
Total debt	$	340		$	764		$	1,056		$	1,071		$	21,746		$	17,492		$	42,469		$	34,759	$	41,907		$	29,152
Debt swapped to fixed:
Amount	$	500		$	600		$	2,600		$	3,600		$	9,000		$	—		$	16,300				$	17,550
Average pay rate		7.43	%		7.57	%		7.99	%		7.60	%		8.18	%		—			7.98	%				8.00	%
Average receive rate		3.74	%		3.74	%		3.74	%		3.74	%		3.74	%		—			3.74	%				5.88	%
Variable basis swaps:
Amount	$	3,600		$	5,450		$	7,200		$	—		$	—		$	—		$	16,250				$	13,045
Average pay rate		0.32	%		0.33	%		0.33	%		—			—			—			0.33	%				2.48	%
Average receive rate		0.24	%		0.24	%		0.24	%		—			—			—			0.24	%				2.00	%

(a) Reflects the remarketing date and not the maturity date for certain debt that is subject to mandatory tender for remarketing prior to maturity. See Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for details concerning long-term debt subject to mandatory tender for remarketing.

As of December 31, 2009, the potential reduction of annual pretax earnings due to a one percentage point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $42 million, taking into account the interest rate swaps discussed in Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009.

Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty’s financial condition, credit rating and other quantitative and qualitative credit criteria and 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. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties’ financial strength, measurement of current and potential future exposures and contract language that provides rights for netting and set-off. Credit enhancements such as parental guarantees, letters of credit, surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to assess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering into an agreement with a counterparty that creates exposure. Additionally, we have established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material 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 — Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions arising from hedging and trading activities totaled $2.616 billion at December 31, 2009. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of December 31, 2009 include $897 million in accounts receivable from the retail sale of electricity to residential and business customers. Cash deposits held as collateral for these receivables totaled $83 million at December 31, 2009. 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.

Assets subject to credit risk also include accounts receivable from electricity transmission and distribution services. This exposure, which totaled $245 million at December 31, 2009, consists almost entirely of noninvestment grade trade accounts receivable. Of this amount, $180 million represents trade accounts receivable from REPs. Oncor has a customer with subsidiaries that collectively represent 11% of the total exposure. No other nonaffiliated parties represent 10% or more of the total exposure.

The remaining credit exposure arises from wholesale energy sales and purchases and hedging and trading activities, including interest rate hedging. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. As of December 31, 2009, the exposure to credit risk from these counterparties totaled $1.474 billion taking into account the standardized master netting contracts and agreements described above but before taking into account $177 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $1.297 billion increased approximately $502 million in the year ended December 31, 2009, driven by increased derivative asset/decreased derivative liability values due to the effect of changes in natural gas prices and interest rates on the values of our hedge positions.

Of this $1.297 billion net exposure, 99.7% is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and our internal credit evaluation process. Those customers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties on this basis.

The following table presents the distribution of credit exposure as of December 31, 2009 arising from wholesale energy sales and purchases and hedging and trading activities. This credit exposure represents wholesale trade accounts receivable and net asset positions on the balance sheet arising from hedging and trading activities after taking into consideration netting and setoff provisions within each contract and any master netting contracts with counterparties.

	Exposure Before  Credit Collateral			Credit Collateral		Net Exposure			Net Exposure by Maturity
									2 years  or less		Between 2-5  years		Greater than 5  years		Total
Investment grade	$	1,467		$	174	$	1,293		$	880	$	413	$	—	$	1,293
Noninvestment grade		7			3		4			4		—		—		4
Totals	$	1,474		$	177	$	1,297		$	884	$	413	$	—	$	1,297
Investment grade		99.5	%				99.7	%
Noninvestment grade		0.5	%				0.3	%

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

Significant (10% or greater) concentration of credit exposure exists with three counterparties, which represented 41%, 37% and 12% of the net $1.297 billion exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and the importance of our business relationship with the counterparty. However, this concentration increases the risk that a default would have a material effect on results of operations.

With respect to credit risk related to the long-term hedging program, over 99% of the transaction volumes are with counterparties with an A credit rating or better. However, there is current and potential credit concentration risk related to the limited number of counterparties that comprise the substantial majority of the program with such counterparties being in the banking and financial sector. The transactions with these counterparties contain certain credit rating provisions that would require the counterparties to post collateral in the event of a material downgrade in the credit rating of the counterparties. An event of default by one or more hedge counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us. While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through the various ongoing risk management measures described above.

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OUR BUSINESSES

References in this “Our Businesses” section to “we,” “our,” “us” and “the company” are to EFH Corp. and/or its subsidiaries, TCEH and/or its subsidiaries, or Oncor and/or its subsidiary as apparent in the context. See “Glossary” for other defined terms.

EFH Corp. Business and Strategy

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

TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. EFCH is the parent company of TCEH and a direct subsidiary of EFH Corp.

TCEH owns or leases 17,519 MW of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas-fueled generation facilities. This amount includes two new lignite-fueled units (Sandow 5 and Oak Grove 1) that achieved substantial completion (as defined in the engineering, procurement and construction (EPC) agreements for the units) in the fourth quarter 2009 but does not include a third new lignite-fueled unit (Oak Grove 2) that achieved substantial completion (as defined in the EPC agreement for the unit) in the second quarter 2010. In addition, TCEH is the largest purchaser of wind-generated electricity in Texas and the fifth largest in the U.S. TCEH provides competitive electricity and related services to more than two million retail electricity customers in Texas.

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EFIH, a direct subsidiary of EFH Corp., is a holding company whose wholly-owned subsidiary, Oncor Holdings, holds a majority interest (approximately 80%) in Oncor, which is principally engaged in providing electricity delivery services to retail electric providers, including subsidiaries of TCEH, that sell power in the north central, eastern and western parts of Texas.

Oncor is engaged in regulated electricity transmission and distribution operations in Texas that are primarily regulated by the PUCT. Oncor provides both distribution services to retail electric providers that sell electricity to consumers and transmission services to other electricity distribution companies, cooperatives and municipalities. Oncor operates the largest transmission and distribution system in Texas, delivering electricity to approximately three million homes and businesses and operating more than 117,000 miles of transmission and distribution lines. A significant portion of Oncor’s revenues represent fees for delivery services provided to TCEH. Distribution revenues from TCEH represented 38% and 39% of Oncor’s total revenues for the years ended December 31, 2009 and 2008, respectively.

EFH Corp. and Oncor have implemented certain structural and operational “ring-fencing” measures based on commitments made by Texas Holdings and Oncor to the PUCT that are intended to enhance the credit quality of Oncor. These measures serve to mitigate Oncor’s and Oncor Holdings’ credit exposure to the Texas Holdings Group and to reduce the risk that the assets and liabilities of Oncor or Oncor Holdings would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities. See Note 1 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for a description of the material features of these “ring-fencing” measures.

At September 30, 2010, we had approximately 9,200 full-time employees (including approximately 3,800 at Oncor), including approximately 2,750 employees (including approximately 660 at Oncor) under collective bargaining agreements.

EFH Corp.’s Market

We operate primarily within the ERCOT market. This market represents approximately 85% of electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the system operator of the interconnected transmission grid for those systems. ERCOT’s membership consists of more than 300 corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, investor-owned utilities, REPs and consumers. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010 — Regulation and Rates — Wholesale Market Design — Nodal Market” for discussion of ERCOT’s implementation of a nodal market design, which was effective in December 2010.

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

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

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The following data is derived from information published by ERCOT:

From 1999 through September 2009, over 41,000 MW of mostly natural gas-fueled and wind generation capacity has been developed in the ERCOT market. Installed generation capacity in the ERCOT market totals approximately 84,000 MW, including approximately 2,500 MW mothballed (idled) capacity, as well as wind (over 9,000 MW), water and other resources that may not be available coincident with system need. In 2010, hourly demand peaked at a record 65,776 MW. ERCOT’s estimate of total available capacity for 2010 reserve margin calculation was approximately 76,000 MW of which, approximately 66% was natural gas-fueled generation and approximately 33% was lignite/coal and nuclear-fueled baseload generation. ERCOT currently has a target reserve margin level of 12.5%; the reserve margin is projected by ERCOT to be 21.4% in 2010, 17.1% in 2011, and drop to 12.9% by 2015. Reserve margin is the difference between system generation capability and anticipated peak load.

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 generally not subject to regulation by the FERC.

Natural gas-fueled generation is the predominant electricity capacity resource in the ERCOT market and accounted for approximately 42% of the electricity produced in the ERCOT market in 2009. Because of the significant natural gas-fueled capacity and the ability of such facilities to more readily increase or decrease production when compared to baseload generation, marginal demand for electricity is usually met by natural gas-fueled facilities. As a result, wholesale electricity prices in ERCOT are highly correlated with natural gas prices.

EFH Corp.’s Strategies

Each of our businesses focuses its operations on key drivers for that business, as described below:

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

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

Other elements of our strategies include:

• Increase value from existing business lines. Our strategy focuses on striving for top quartile or better performance across our operations in terms of safety, reliability, cost and customer service. In establishing tactical objectives, we incorporate the following core operating principles:

• Safety: Placing the safety of communities, customers and employees first;

• Environmental Stewardship: Continuing to make strategic and operational improvements that lead to cleaner air, land and water;

• Customer Focus: Delivering products and superior service to help customers more effectively manage their use of electricity;

• Community Focus: Being an integral part of the communities in which we live, work and serve;

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• Operational Excellence: Incorporating continuous improvement and financial discipline in all aspects of the business to achieve top-tier results that maximize the value of the company for stakeholders, including operating world-class facilities that produce and deliver safe and dependable electricity at affordable prices; and

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

• Pursue growth opportunities across business lines. Scale in our operating businesses allows us to take part in large capital investments, such as new generation projects and investments in the transmission and distribution system, with a smaller fraction of overall capital at risk and with an enhanced ability to streamline costs. We expect to also explore smaller-scale growth initiatives 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 include:

o Pursue generation development opportunities to help meet ERCOT’s growing electricity needs over the longer term from a diverse range of alternatives such as nuclear, renewable energy and advanced coal technologies.

o Profitably increase the number of retail customers served throughout the competitive ERCOT market areas by delivering superior value through high quality customer service and innovative energy products, including leading energy efficiency initiatives and service offerings.

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

• Reduce the volatility of cash flows through a commodity risk management strategy. The strong historical correlation between natural gas prices and wholesale electricity prices in the ERCOT market provides us an opportunity to manage our exposure to variability of wholesale electricity prices. We have established 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, TCEH has entered into market transactions involving natural gas-related financial instruments, and as of September 30, 2010, has effectively sold forward approximately 1.25 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 156,000 GWh at an assumed 8.0 market heat rate) for the period October 1, 2010 through December 31, 2014 at weighted average annual hedge prices ranging from $7.82 per MMBtu to $7.19 per MMBtu. These transactions, as well as forward power sales, have effectively hedged an estimated 64% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning October 1, 2010 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which are expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If this correlation changes, the cash flows targeted under the long-term hedging program may not be achieved. As of September 30, 2010, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the senior secured cash posting credit facility of TCEH discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010 — Financial Condition — Liquidity and Capital Resources — Liquidity Effects of Commodity Hedging and Trading Activities”), thereby reducing the cash and letter of credit collateral requirements for the hedging program.

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• Pursue new environmental initiatives. We are committed to continue to operate in compliance with all environmental laws, rules and regulations and to reduce our impact on the environment. EFH Corp.’s Sustainable Energy Advisory Board advises in the pursuit of technology development opportunities that reduce our impact on the environment while balancing the need to help address the energy requirements of Texas. The Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, labor unions, customers, economic development in Texas and technology/reliability standards. In addition, we are focused on and are pursuing opportunities to reduce emissions from our existing and new lignite/coal-fueled generation units in the ERCOT market. We have voluntarily committed to reduce emissions of mercury, NO_x and SO₂ at our existing units. We expect to make these reductions through a combination of investment in new emission control equipment, new coal cleaning technologies and optimizing fuel blends. In addition, we expect to invest $400 million over a five-year period that began in 2008 in programs designed to encourage customer electricity demand efficiencies, representing $200 million more than amounts planned to be invested by Oncor to meet regulatory requirements. As of December 31, 2009, we invested a total of $145 million in these programs.

Seasonality

Our revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.

Operating Segments

We have aligned and report our 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 24 to EFH Corp.’s historical consolidated financial statements as of and for the year ended December 31, 2009 and Note 15 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010 for additional financial information for the segments.

Competitive Electric Segment

Key management activities, including commodity risk management, are performed on an integrated basis. However, for purposes of operational accountability, performance management and market identity, the segment operations have been grouped into Luminant, which is engaged in electricity generation and wholesale markets activities, and TXU Energy, which is engaged in retail electricity sales activities. These activities are conducted through separate legal entities.

Luminant — Luminant’s existing electricity generation fleet consists of 18 plants in Texas with total installed nameplate generating capacity as shown in the table below:

Fuel Type	Installed Nameplate Capacity (MW)		Number of Plants		Number of Units (a)
Nuclear		2,300		1		2
Lignite/coal (b)		7,217		5		11
Natural gas (c)(d)		8,002		12		35
Total		17,519		18		48

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

(b) Does not include generation capacity of the second unit at Oak Grove, which recently achieved substantial completion (as defined in the EPC agreement for the unit), as discussed below under “Lignite/Coal-Fueled Generation Operations.”

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(c) Includes 3,886 MW representing 11 units mothballed and not currently available for dispatch, including eight units totaling 2,771 MW planned to be retired on December 31, 2010, and 655 MW representing two units operated under reliability-must-run (RMR) contracts with ERCOT. See “Natural Gas-Fueled Generation Operations” below.

(d) Includes 1,268 MW representing eight units currently operated for unaffiliated 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 wholesale power prices (i.e., economic backdown) or ERCOT instruction. The natural gas-fueled generation units supplement the baseload generation capacity in meeting consumption in peak demand periods as production from a certain number of these units can more readily be ramped up or down as demand warrants.

Nuclear Generation Operations — Luminant operates two nuclear generation units at the Comanche Peak plant, each of which is designed for a capacity of 1,150 MW. Comanche Peak’s Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, and are generally operated at full capacity to meet the load requirements in ERCOT. Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, the refueling cycle results in the refueling of both units during the same year, which last occurred in 2008. While one unit is undergoing a refueling outage, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance, modification and testing activities are completed that cannot be accomplished when the unit is in operation. Over the last three years, excluding the 55-day outage in 2007 to refuel and replace the steam generators and reactor vessel head in Unit 1, the refueling outage period per unit has ranged from 19 to 27 days. The Comanche Peak plant operated at a capacity factor of 93.5% in 2007, reflecting the planned extended refueling outage to replace the steam generator and reactor vessel head in Unit 1, 95.2% in 2008, reflecting refueling of both units and 100.0% in 2009.

Luminant has contracts in place for all of its uranium, nuclear fuel conversion services and nuclear fuel enrichment services for 2010. For the period of 2011-2015, Luminant has contracts in place for the acquisition of approximately 76% of its uranium requirements, 90% of its nuclear fuel conversion services requirements and 84% of its nuclear fuel enrichment services requirements. In addition, Luminant has contracts for all of its nuclear fuel fabrication services requirements through 2018 and a contract for a portion of its uranium requirements through 2024. Contracts for the acquisition of a portion of the nuclear fuel enrichment services requirements through 2023 and 2029 are also complete. Luminant does not anticipate any significant difficulties in acquiring uranium and contracting for associated conversion services and enrichment services in the foreseeable future.

Luminant believes its on-site used nuclear fuel storage capability is sufficient for a minimum of three 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. Current on-site used nuclear fuel storage capability will require the use of the industry technique of dry cask storage within the next three years.

The Comanche Peak nuclear generation units have an estimated useful life of 60 years from the date of commercial operation. Therefore, assuming that Luminant receives 20-year license extensions, similar to what has been granted by the NRC to several other commercial generation reactors over the past several years, plant decommissioning activities would be scheduled to begin in 2050 for Comanche Peak Unit 1 and 2053 for Unit 2 and common facilities. Decommissioning costs will be paid from a decommissioning trust that, pursuant to state law, is funded from Oncor’s customers through an ongoing delivery surcharge. (See Note 19 to EFH Corp.’s historical consolidated financial statements as of and for the year ended December 31, 2009 for discussion of the decommissioning trust fund.)

Nuclear insurance provisions are discussed in Note 13 to EFH Corp.’s historical consolidated financial statements as of and for the year ended December 31, 2009.

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Nuclear Generation Development —In September 2008, a subsidiary of TCEH filed a combined operating license application with the NRC for two new nuclear generation units, each with approximately 1,700 MW (gross capacity), at its existing Comanche Peak nuclear generation site. In connection with the filing of the application, in January 2009, subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, Comanche Peak Nuclear Power Company (CPNPC), to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. The TCEH subsidiary owns an 88% interest in CPNPC, and a MHI subsidiary owns a 12% interest.

In March 2009, the NRC announced an official review schedule for the license application. Based on the schedule, the NRC expects to complete its review by December 2011, and it is expected that a license would be issued approximately one year later. In November 2009, CPNPC filed a comprehensive revision to the license application that updated the license application for developments occurring after the initial filing.

In 2009, the DOE announced that it had selected four applicants to proceed to the due diligence phase of its Loan Guarantee Program and to commence negotiations towards potential loan guarantees for their respective generation projects. CPNPC was not among the initial four applicants selected by the DOE; however, CPNPC continues to update the DOE on its progress, with the goal of securing a DOE loan guarantee for financing the proposed units prior to commencement of construction.

Lignite/Coal-Fueled Generation Operations — Luminant’s lignite/coal-fueled generation fleet capacity totals 7,217 MW (including two recently completed new units) and consists of the Big Brown (2 units), Monticello (3 units), Martin Lake (3 units), Oak Grove (1 unit) and Sandow (2 units) plants. These plants are generally operated at full capacity to help meet the load requirements in ERCOT. Maintenance outages are scheduled during off-peak demand periods. Over the last three years, the total annual scheduled and unscheduled outages per unit averaged 31 days. Luminant’s lignite/coal-fueled generation fleet operated at a capacity factor of 90.9% in 2007, 87.6% in 2008 and 86.5% in 2009, which represents top quartile performance of U.S. coal-fueled generation facilities. The 2008 performance reflects extended unplanned outages at several units, and the 2009 performance reflects increased economic backdown of the units.

Luminant has substantially completed a program to develop and construct three lignite-fueled generation units with a total estimated capacity of 2,200 MW. The three units consist of one unit at a leased site that is adjacent to an existing owned lignite-fueled generation unit (Sandow) and two units at an owned site (Oak Grove). The Sandow unit and the first Oak Grove unit achieved substantial completion (as defined in the EPC agreements for the respective units) effective in the fourth quarter 2009. The second Oak Grove unit achieved substantial completion (as defined in the EPC agreement for the unit) effective in the second quarter 2010. Accordingly, the company has operational control of these units.

Aggregate cash capital expenditures for these three units are expected to total approximately $3.25 billion including all construction, site preparation and mining development costs, of which approximately $3.23 billion was spent as of September 30, 2010. The investment includes approximately $500 million for state-of-the-art emissions controls for the three new units. Including capitalized interest and the step-up in construction work-in-process balances to fair value as a result of purchase accounting for the Merger in 2007, carrying value of the units are estimated to total approximately $4.8 billion upon completion. Agreements were executed with EPC contractors Bechtel Power Corporation and Fluor Enterprises, Inc. to engineer and construct the units at Sandow and Oak Grove, respectively.

Luminant also has an environmental retrofit program under which it plans to install additional environmental control systems at its existing lignite/coal-fueled generation facilities. Capital expenditures associated with these additional environmental control systems could exceed $1.0 billion, of which $326 million was spent through 2009. Luminant has not yet completed all detailed cost and engineering studies for the additional environmental systems, and the cost estimates could change materially as it determines the details of and further evaluates the engineering and construction costs related to these investments.

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Approximately 47% of the fuel used at Luminant’s lignite/coal-fueled generation plants in 2009 was supplied from lignite reserves owned in fee or leased surface-minable deposits dedicated to the Big Brown, Monticello, Martin Lake and Oak Grove plants, which were constructed adjacent to the reserves. Luminant owns in fee or has under lease an estimated 843 million tons of lignite reserves dedicated to its generation plants and 241 million tons associated with an undivided interest in the lignite mine that provides fuel for the Sandow facility. Luminant also owns in fee or has under lease in excess of 85 million tons of reserves not currently dedicated to specific generation plants. In 2009, Luminant recovered approximately 20 million tons of lignite to fuel its generation plants. Luminant utilizes owned and/or leased equipment to remove the overburden and recover the lignite.

Luminant’s lignite mining operations include extensive reclamation activities that return the land to productive uses such as wildlife habitats, commercial timberland and pasture land. In 2009, Luminant reclaimed 1,485 acres of land. In addition, Luminant planted more than 1.1 million trees in 2009, the majority of which were part of the reclamation effort.

Luminant 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’s generation plants by railcar. Based on its current usage, Luminant believes that it has sufficient lignite reserves for the foreseeable future and has contracted approximately 99% of its western coal resources and all of the related transportation through 2011.

Natural Gas-Fueled Generation Operations — Luminant’s fleet of 35 natural gas-fueled generation units totaling 8,002 MW of capacity includes 2,193 MW of currently available capacity, 1,923 MW of capacity being operated for unaffiliated third parties (including 655 MW under RMR agreements with ERCOT), and 3,886 MW of capacity currently mothballed (idled), including 2,771 MW of capacity planned to be retired on December 31, 2010. The natural gas-fueled units predominantly serve as peaking units that can be ramped up or down as demand for electricity warrants.

Wholesale Operations — Luminant’s wholesale operations play a pivotal role in our competitive business portfolio by optimally dispatching the generation fleet, including the baseload facilities, sourcing TXU Energy’s and other customers’ electricity requirements and managing commodity price risk.

Our commodity price exposure is managed across the complementary Luminant generation and TXU Energy retail businesses on a portfolio basis. Under this approach, Luminant’s wholesale operations manage 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’s wholesale operations manage this commodity price and heat rate exposure through asset management and hedging activities. These operations provide TXU Energy and other retail and wholesale customers with electricity and related services to meet their demands and the operating requirements of ERCOT. Luminant also sells forward generation and seeks to maximize the economic value of the generation fleet, particularly the baseload facilities. In consideration of operational production and customer consumption levels that can be highly variable, as well as opportunities for long-term purchases and sales with large wholesale market participants, Luminant buys and sells electricity in short-term transactions and executes longer-term forward electricity purchase and sales agreements. Luminant is the largest purchaser of wind-generated electricity in Texas and the fifth largest in the U.S. with more than 900 MW of existing wind power under contract.

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

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The wholesale operations also dispatch Luminant’s available natural gas-fueled generation capacity. Luminant’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’s wholesale operations coordinate the overall commercial strategy for these plants working closely with other Luminant operations. In addition, the wholesale operations manage the natural gas and fuel-oil procurement requirements for Luminant’s natural gas-fueled generation fleet.

Luminant’s wholesale operations engage in commercial operations such as physical purchases, storage and sales of natural gas, electricity and natural gas trading and third-party energy management. Natural gas operations include direct purchases from natural gas producers, transportation agreements, storage leases and commercial retail sales. Luminant currently manages approximately 11 billion cubic feet of natural gas storage capacity.

Luminant’s wholesale operations manage exposure to wholesale commodity and credit-related risk within established transactional risk management policies, limits and controls. These policies, limits and controls have been structured so that they are practical in application and consistent with stated business objectives. Risk management processes include capturing transactions, performing and validating valuations and reporting exposures on a daily basis using risk management information systems designed to support a large transactional portfolio. A risk management forum meets regularly to ensure that business practices comply with approved transactional limits, commodities, instruments, exchanges and markets. Transactional risks are monitored and limits are enforced to comply with the established risk policy. Luminant has a disciplinary program to address any violations of the risk management policies and periodically reviews these policies to ensure they are responsive to changing market and business conditions.

TXU Energy — TXU Energy serves more than two million residential and commercial retail electricity customers in Texas with approximately 61% of retail revenues in 2009 from residential customers. Texas is one of the fastest growing states in the nation with a diverse economy and, as a result, has attracted a number of competitors into the retail electricity market; consequently, competition is 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. There are more than 360 active REPs certified to compete within the State of Texas.

TXU Energy’s strategy focuses on providing its customers with high quality customer service and creating new products and services to meet customer needs; accordingly, a new customer management computer system was implemented in 2009, and other customer care enhancements are being implemented to further improve customer satisfaction. TXU Energy offers a wide range of residential products to meet various customer needs. TXU Energy is investing $100 million over five years ending in 2012, including a total of $20 million spent as of December 31, 2009, in energy efficiency initiatives as part of a program to offer customers a broad set of innovative energy products and services.

Regulation — Luminant is an exempt wholesale generator under the Energy Policy Act of 2005 and is subject to the jurisdiction of the NRC with respect to its nuclear generation plant. NRC regulations govern the granting of licenses for the construction and operation of nuclear-fueled generation facilities and subject such facilities to continuing review and regulation. Luminant also holds a power marketer license from the FERC and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior and any other competition-related rules and regulations under the Federal Power Act that are administered by the FERC.

Luminant is also subject to the jurisdiction of the PUCT’s oversight of the competitive ERCOT wholesale electricity market. PUCT rules do not set wholesale power prices in the market but do provide certain limits and framework for such pricing and market behavior. Luminant is also subject to the requirements of the ERCOT Protocols, the soon to be effective Nodal Protocols and ERCOT reliability standards as adopted and enforced by the TRE and the NERC.

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TXU Energy is a licensed REP under the Texas Electric Choice Act and is subject to the jurisdiction of the PUCT with respect to provision of electricity service in ERCOT. PUCT rules govern the granting of licenses for REPs, including oversight but not setting of prices charged. TXU Energy is also subject to the requirements of the ERCOT Protocols, the soon to be effective Nodal Protocols and ERCOT reliability standards as adopted and enforced by the TRE and the NERC.

Regulated Delivery Segment

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

Oncor is not a seller of electricity, nor does it purchase electricity for resale. It provides transmission services to other electricity distribution companies, cooperatives and municipalities. It provides distribution services to REPs, which sell electricity to retail customers. Oncor is also subject to the requirements of the ERCOT Protocols, the soon to be effective Nodal Protocols and ERCOT reliability standards as adopted and enforced by the TRE and the NERC.

Performance — Oncor achieved market-leading electricity delivery performance in nine out of 12 key PUCT market metrics in 2009. These metrics measure the success of transmission and distribution companies in facilitating customer transactions in the competitive Texas electricity market. Two additional metrics for expedited switching have been added by the PUCT in 2010.

Investing in Infrastructure and Technology — In 2009, Oncor invested $1.0 billion in its network to construct, rebuild and upgrade transmission lines and associated facilities, to extend the distribution infrastructure, and to pursue certain initiatives in infrastructure maintenance and information technology. Reflecting its commitment to infrastructure, in September 2008, Oncor and several other ERCOT utilities filed with the PUCT a plan to participate in the construction of transmission improvements designed to interconnect existing and future renewable energy facilities to transmit electricity from Competitive Renewable Energy Zones (CREZs) identified by the PUCT. In 2009, the PUCT awarded approximately $1.75 billion of CREZ construction projects to Oncor. The projects involve the construction of transmission lines to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of the state. As of September 30, 2010, Oncor’s CREZ-related capital expenditures totaled $256 million. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010 — Regulatory Matters.”

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Oncor’s technology upgrade initiatives include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs. Oncor’s plans provide for the full deployment of over three million advanced meters by the end of 2012 to all residential and most non-residential retail electricity customers in Oncor’s service area. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits. As of September 30, 2010, Oncor has installed approximately 1,343,000 advanced digital meters. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for Texas market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. In addition to the potential energy efficiencies from advanced metering, Oncor expects to invest over $300 million ($100 million in excess of regulatory requirements) over the five years ending in 2012 in programs designed to improve customer electricity demand efficiencies. As of December 31, 2009, Oncor has invested $125 million in these programs, including $67 million in 2009, and 22% of the amount in excess of regulatory requirements has been spent.

In a stipulation with several parties that was approved by the PUCT (as discussed in Note 6 to EFH Corp.’s historical consolidated financial statements as of and for the year ended December 31, 2009), Oncor committed to a variety of actions, including minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. Approximately 50% of this total was spent as of December 31, 2009. This spending does not include the CREZ facilities.

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

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

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

Provisions of the 1999 Restructuring Legislation allow Oncor to annually update its transmission rates to reflect changes in invested capital. These “capital tracker” 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.

At December 31, 2009, Oncor’s transmission facilities includes approximately 5,173 circuit miles of 345-kV transmission lines and approximately 9,954 circuit miles of 138-and 69-kV transmission lines. Sixty-two generation facilities totaling 36,165 MW are directly connected to Oncor’s transmission system, and 277 transmission stations and 702 distribution substations are served from Oncor’s transmission system.

At December 31, 2009, Oncor’s transmission facilities have the following connections to other transmission grids in Texas:

	Number of Interconnected Lines
Grid Connections	345kV		138kV		69kV
Centerpoint Energy Inc.		8		—		—
American Electric Power Company, Inc (a)		4		7		12
Lower Colorado River Authority		6		20		3
Texas Municipal Power Agency		8		6		—
Texas New Mexico Power		2		9		11
Brazos Electric Power Cooperative		4		104		20
Rayburn Country Electric Cooperative		—		32		7
City of Georgetown		—		2		—
Tex-La Electric Cooperative		—		11		1
Other small systems operating wholly within Texas		—		3		2

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(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 3,097 distribution feeders.

The Oncor distribution system includes over 3.1 million points of delivery. Over the past five years, the number of distribution system points of delivery served by Oncor, excluding lighting sites, grew an average of approximately 1.26% per year, adding approximately 24,689 points of delivery in 2009.

The Oncor distribution system consists of approximately 56,260 miles of overhead primary conductors, approximately 21,587 miles of overhead secondary and street light conductors, approximately 15,352 miles of underground primary conductors and approximately 9,528 miles of underground secondary and street light conductors. The majority of the distribution system operates at 25-kV and 12.5-kV.

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

Customers — Oncor’s transmission customers consist of municipalities, electric cooperatives and other distribution companies. Oncor’s distribution customers consist of more than 70 REPs in Oncor’s certificated service area, including TCEH. Distribution revenues from TCEH represented 38% of Oncor’s total revenues for 2009, and revenues from subsidiaries of Reliant Energy, Inc., each of which is a non-affiliated REP, represented 14% of Oncor’s total revenues for 2009. No other customer represented more than 10% of Oncor’s total operating revenues. The consumers of the electricity delivered by Oncor are free to choose their electricity supplier from REPs who compete for their business.

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

The PUCT has original jurisdiction over transmission and distribution rates and services in unincorporated areas and in those municipalities that have ceded original jurisdiction to the PUCT and has exclusive appellate jurisdiction to review the rate and service orders and ordinances of municipalities. Generally, PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that does not have the prior approval of the appropriate regulatory authority (PUCT or municipality with original jurisdiction). In accordance with a stipulation approved by the PUCT, Oncor filed a rate case with the PUCT in June 2008, based on a test year ended December 31, 2007. In August 2009, the PUCT issued a final order with respect to the rate review as discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Year Ended December 31, 2009 — Regulation and Rates.”

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

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

Environmental Regulations and Related Considerations

Global Climate Change

Background — A growing concern has emerged nationally and internationally about global climate change and how greenhouse gas (GHG) emissions, such as CO₂, might contribute to global climate change. We produce GHG emissions from the direct combustion of fossil fuels at our generation plants, primarily our lignite/coal-fueled generation units. CO₂, methane and nitrous oxide are emitted in this combustion process, with CO₂ representing the largest portion of these GHG emissions. GHG emissions (primarily CO₂) from our combustion of fossil fuels represent the substantial majority of our total GHG emissions. For 2009, we estimate that our generation facilities produced 54 million short tons of CO₂ based on continuously monitored data reported to and approved by the EPA. The three new lignite-fueled units that achieved substantial completion (as defined in the EPC agreements for the units) in the fourth quarter 2009 and the second quarter 2010 will generate additional CO₂ emissions. Other aspects of our operations result in emissions of GHGs including, among other things, coal piles at our generation plants, sulfur hexafluoride in our electric operations, refrigerant from our chilling and cooling equipment, fossil fuel combustion in our motor vehicles and electricity usage at our facilities and headquarters. Because a substantial portion of our generation portfolio consists of lignite/coal-fueled generation plants, including the three new lignite-fueled generation units that are substantially complete, our financial condition and/or results of operations could be materially adversely affected by the enactment of statutes or regulations that mandate a reduction in GHG emissions or that impose financial penalties, costs or taxes on those that produce GHG emissions. See “Risk Factors” for additional discussion of risks posed to us regarding global climate change regulation.

Global Climate Change Legislation — Several bills have been introduced in the U.S. Congress or advocated by the Obama Administration that are intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon emissions (carbon tax) and incentives for the development of low-carbon technology. In addition to potential federal legislation to regulate GHG emissions, the U.S. Congress might also consider other legislation that could result in the reduction of GHG emissions, such as the establishment of renewable energy portfolio standards.

Through our own evaluation and working in tandem with other companies and industry trade associations, we have supported the development of an integrated package of recommendations for the federal government to address the global climate change issue through federal legislation, including GHG emissions reduction targets for total U.S. GHG emissions and rigorous cost containment measures to ensure that program costs are not prohibitive. In the event GHG legislation involving a cap-and-trade program is enacted, we believe that such a program should be mandatory, economy-wide, consistent with expected technology development timelines and designed in a way to limit potential harm to the economy and protect consumers. We contend that any mechanism for allocation of GHG emission allowances should include substantial allocation of allowances to offset the cost of GHG regulation, including the cost to electricity consumers. In addition, we participate in a voluntary electric utility industry sector climate change initiative in partnership with the DOE. Our strategies are generally consistent with the “EEI Global Climate Change Points of Agreement” published by the Edison Electric Institute in January 2009 and “The Carbon Principles” announced in February 2008 by three major financial institutions. Finally, we have created a Sustainable Energy Advisory Board that advises us on technology development opportunities that reduce the effects of our operations on the environment while balancing the need to address the energy requirements of Texas. Our Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, customers, economic development in Texas and technology/reliability standards. If, despite these efforts, a substantial number of our investors, customers or others refuse to do business with us because of our GHG emissions, it could have a material adverse effect on our results of operations, financial position and liquidity.

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Federal Level —Several bills have been introduced in the U.S. Congress or advocated by the Obama Administration that are intended to address climate change using different approaches, including most prominently a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade). These bills include the Waxman-Markey bill, known as the American Clean Energy and Security Act of 2009 (Waxman-Markey), the Kerry-Boxer bill, known as the Clean Energy Jobs and American Power Act (Kerry-Boxer) and the Kerry-Lieberman bill, known as the American Power Act (Kerry-Lieberman). This proposed legislation is not law, but in June 2009 Waxman-Markey was passed by the U.S. House of Representatives and sent to the U.S. Senate for consideration. Kerry-Boxer was reported out of the U.S. Senate Environment and Public Works Committee, but has not been taken up by the Senate as a whole. Kerry-Lieberman was released by its sponsors in May 2010 when it appeared that progress on passing Kerry-Boxer had stalled.

As currently proposed, Waxman-Markey takes several approaches to address GHG emissions, including establishing renewable energy and energy efficiency standards, establishing performance standards for coal-fueled electricity generation units, and creating an economy-wide cap-and-trade program. The renewable energy and energy efficiency standards would require retail electricity suppliers to meet 6% of their load with renewable energy sources by 2012, increasing to 20% of their load by 2020, some of which could be met by energy efficiency measures. The performance standards for coal-fueled electricity generation units would require a 65% reduction in CO₂ emissions for subject generation units initially permitted after January 1, 2020, and a 50% reduction in CO₂ emissions for subject electricity generation units initially permitted between January 1, 2009 and January 1, 2020 once certain technology deployment criteria are met but no later than January 1, 2025. The cap-and-trade program would require emissions from capped sources, including coal-fueled electricity generation units, to be reduced 3% below 2005 levels by 2012, 17% by 2020, 42% by 2030 and 83% by 2050. The version of Waxman-Markey passed by the U.S. House of Representatives included provisions that allocated a large percentage of the emissions allowances at no charge to various groups that would be impacted by such a cap-and-trade program, including certain merchant coal-fueled generation units. The Kerry-Boxer proposal employs a cap and trade approach similar to Waxman-Markey, but requires a 20% reduction in CO₂ emissions levels by 2020 and provides a smaller grant of emission allowances to the electric power sector, including merchant coal-fueled generation units. Kerry-Boxer does not include a renewable energy and energy efficiency standard, which is addressed in a separate proposal in the U.S. Senate.

Recent developments in the U.S. Congress indicate that the prospects for passage of any cap-and-trade legislation in this Congress are not likely. However, if any of them or similar legislation were to be adopted, our costs of compliance could be material.

In December 2009, the EPA issued a finding that GHG emissions endanger human health and the environment and that emissions from motor vehicles contribute to that endangerment. The EPA’s finding required it to begin regulating GHG emissions from motor vehicles and ultimately stationary sources under existing provisions of the federal Clean Air Act. Following its endangerment finding, the EPA took three regulatory actions with respect to the control of GHG emissions. First, in March 2010, the EPA completed a reconsideration of a memorandum issued in December 2008 by then EPA Administrator Stephen Johnson on the issue of when the Clean Air Act’s Prevention of Significant Deterioration (PSD) program would apply to newly identified pollutants such as GHG’s. The EPA determined that the Clean Air Act’s PSD permit requirements would apply when a nation-wide rule requiring the control of a pollutant takes effect. Under this determination, the earliest time that PSD permitting requirements would apply to GHG emissions from stationary sources, including our power generation facilities, would be January 2011 — the first date that new motor vehicles must meet the new GHG standards. Second, in April 2010, the EPA adopted GHG emission standards for certain new motor vehicles. Third, in June 2010, the EPA finalized its so-called “tailoring rule” that established new thresholds of GHG emissions for the applicability of permits under the Clean Air Act for stationary sources, including our power generation facilities. The EPA’s tailoring rule defines the threshold of GHG emissions for determining applicability of the Clean Air Act’s permitting programs and PSD program at levels greater than the lower emission thresholds contained in the Clean Air Act. In addition, in September 2009, the EPA issued a final rule requiring the reporting, by March 2011, of calendar year 2010 GHG emissions from specified large GHG emissions sources in the U.S. (such reporting rule would apply to our lignite-fueled generation facilities).

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As with the regional GHG regulatory programs, any federal GHG legislation is expected to limit, to some extent, the EPA’s authority to regulate GHGs under existing Clean Air Act regulatory programs, but if Congress fails to pass GHG legislation, the EPA is expected to continue its announced Clean Air Act regulatory actions. Our costs of complying with future EPA limitations on GHG emissions could be material.

In September 2009, the U.S. Court of Appeals for the Second Circuit issued a decision in the case ofState of Connecticut v. American Electric Power Company Inc. holding that various states, a municipality and certain private trusts have standing to sue and have sufficiently alleged a cause of action under the federal common law of nuisance for injuries allegedly caused by the defendant power generation companies’ emissions of GHGs. The decision does not address the merits of the nuisance claim, and is still subject to appeal.

In October 2009, the U.S. Court of Appeals for the Fifth Circuit issued a decision in the case ofComer v. Murphy Oil USA holding that certain Mississippi residents have standing to sue to pursue state law nuisance, negligence and trespass claims for injuries purportedly suffered because the defendants’ emissions of GHGs allegedly increased the destructive force of Hurricane Katrina. This decision, like theAmerican Electric Power decision discussed above, does not address the merits of such a nuisance claim and is still subject to appeal.

In September 2009, the U.S. District Court for the Northern District of California issued a decision in the case ofNative Village of Kivalina v. ExxonMobil Corporation dismissing claims asserted by an Eskimo village that emissions of GHGs from approximately 24 oil and energy companies are causing global warming, which has damaged the arctic sea ice that protects the village from winter storms and erosion. The court dismissed the claims because they raised nonjudiciable political questions and because plaintiffs lacked standing to sue. The decision is subject to appeal.

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

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

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International Level —The U.S. currently is not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC). The United Nations’ Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008 to 2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference, the Bali Action Plan was adopted, which identifies a work group, process and timeline for the consideration of possible post-2012 international actions to further address climate change. In December 2009, leaders of developed and developing countries met in Copenhagen under the UNFCCC and issued the Copenhagen Accord. The Copenhagen Accord provides a mechanism for countries to make economy-wide GHG emission mitigation commitments for reducing emissions of GHGs by 2020 and provides for developed countries to fund GHG emission mitigation projects in developing countries. President Obama participated in the development of, and endorsed, the Copenhagen Accord. In January 2010, the U.S. informed the United Nations that it would reduce GHG emissions by 17% from 2005 levels by 2020, contingent on Congress passing climate change legislation.

We continue to assess the risks posed by possible future legislative or regulatory changes pertaining to GHG emissions. Because the proposals described above are in their formative stages, we are unable to predict the potential effects on our business, financial condition and/or results of operations; however, any such effects could be material. The effect will depend, in large part, on the specific requirements of the legislation or regulation and how much, if any, of the costs are included in wholesale prices.

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

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

• Investing in Energy Efficiency Initiatives by Oncor — In addition to the potential energy efficiencies from advanced metering, Oncor expects to invest over $300 million in energy efficiency initiatives over a five-year period that began in 2008 through such efforts as traveling across the State of Texas educating consumers about electricity, including the benefits of energy efficiency, advanced meters and renewable energy, and investment of over $16 million in the installation of solar photovoltaic systems in customer’s homes and facilities that is expected to result in savings of up to 4.8 million kWh of electricity;

• Participating in the CREZ Program — Oncor has been selected by the PUCT to construct approximately $1.75 billion of CREZ transmission facilities that are designed to connect existing and future renewable energy facilities to the electricity transmission system in ERCOT;

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

• Promoting the Use of Solar Power — TXU Energy currently purchases surplus renewable distributed generation from qualified customers. In addition, TXU Energy’s Solar Academy works with Texas school districts to teach and demonstrate the benefits of solar power;

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• Investing in Technology — We continue to evaluate the development and commercialization of cleaner power facility technologies; technologies that support sequestration and/or reduction of CO₂; incremental renewable sources of electricity, including wind and solar power; energy storage, including advanced battery and compressed air storage, as well as related technologies that seek to lower emissions intensity. Additionally, we continue to explore the advances in electric cars and plug-in hybrid electric vehicles that have the potential to reduce overall GHG emissions;

• Evaluating the Development of a New Nuclear Generation Facility — We have filed an application with the NRC for combined construction and operating licenses for up to 3,400 MW of new nuclear generation capacity (the lowest GHG emission source of baseload generation currently available) at our Comanche Peak nuclear generation facility. In addition, we have (i) filed a loan guarantee application with the DOE for financing of the proposed units and (ii) formed a joint venture with Mitsubishi Heavy Industries Ltd. (MHI) to further develop the units using MHI’s US-Advanced Pressurized Water Reactor technology, and

• Offsetting GHG Emissions by Planting Trees —We are engaged in a number of tree planting programs that offset GHG emissions, resulting in the planting of over 1.1 million trees in 2009. The majority of these trees were planted as part of our mining reclamation efforts but also include TXU Energy’s Urban Tree Farm program, which has planted more than 150,000 trees since its inception in 2002.

Other Environmental Regulations

Recent EPA Actions — The EPA has recently completed several regulatory actions establishing new requirements for control of certain emissions from sources that include coal-fueled generation facilities. It is also currently considering several other regulatory actions, as well as contemplating future additional regulatory actions, in each case that may affect our coal-fueled generation facilities.

Each of our coal-fueled generation facilities is currently equipped with substantial emissions control equipment. All of our coal-fueled generation facilities are equipped with activated carbon injection systems to reduce mercury emissions. Flue gas desulfurization systems designed primarily to reduce sulfur dioxide emissions are installed at Oak Grove Units 1 and 2, Sandow Units 4 and 5, Martin Lake Units 1, 2, and 3, and Monticello Unit 3. Selective catalytic reduction systems designed to reduce nitrogen oxide emissions are installed at Oak Grove Units 1 and 2 and Sandow Unit 4. Selective non-catalytic reduction systems designed to reduce nitrogen oxide emissions are installed at Sandow Unit 5, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Fabric filter systems designed primarily to reduce particulate matter emissions are installed at Oak Grove Units 1 and 2, Sandow Unit 5, Monticello Units 1 and 2, and Big Brown Units 1 and 2. Electrostatic precipitator systems designed primarily to reduce particulate matter emissions are installed at Sandow Unit 4, Martin Lake Units 1, 2, and 3, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Sandow Unit 5 uses a fluidized bed combustion process that facilitates control of nitrogen oxides and sulfur dioxide. Flue gas desulfurization systems, fabric filter systems, and electrostatic precipitator systems also assist in reducing mercury and other emissions.

There is no assurance that the currently-installed emissions control equipment at our coal-fueled generation facilities will satisfy the requirements under any future EPA or TCEQ regulations. Some of the potential EPA or TCEQ regulatory actions could require us to install significant additional control equipment, resulting in material costs of compliance for our generation units, including capital expenditures and higher operating costs. These costs could result in material adverse effects on our financial condition, liquidity and results of 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_xemission standards. Our generation plants meet these SO₂ allowance requirements and NO_x emission rates.

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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 between 2009 and 2015, were based on a cap and trade approach (market-based) in which a cap was put on the total quantity of emissions allowed in 28 eastern states (including Texas). Emitters were required to have allowances for each ton emitted, and emitters were allowed to trade emissions under the cap. In July 2008, the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit Court) vacated CAIR. In December 2008, in response to an EPA petition, the D.C. Circuit Court reversed, in part, its previous ruling. Such reversal confirmed CAIR is not valid, but allowed it to remain in place while the EPA revises CAIR to correct the previously identified shortcomings. In July 2010, the EPA released a proposed rule called the Clean Air Transport Rule (CATR). The CATR, as proposed, would replace CAIR in 2012 and would require no additional emission reductions for Luminant. However, we cannot predict the impact of a final rule on our business, results of operations and financial condition. See Note 3 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for discussion of the impairment of emission allowances intangible assets.

In 2005, the EPA also published a final rule requiring reductions of mercury emissions from coal-fueled generation plants. The Clean Air Mercury Rule (CAMR) was based on a nationwide cap and trade approach. The mercury reductions were required to be phased in between 2010 and 2018. In March 2008, the D.C. Circuit Court vacated CAMR. In February 2009, the U.S. Supreme Court refused to hear the appeal of the D.C. Circuit Court’s ruling. The EPA agreed, in a federal court consent decree, to publish proposed regulations concerning emissions of mercury and other hazardous air pollutants from electricity generating units by March 2011, and to finalize those regulations late in 2011. We cannot predict the substance of any final EPA regulations on such hazardous air pollutants. However, the EPA has informally indicated that recently proposed regulations regarding hazardous air pollutants from industrial boilers may serve as a template for the forthcoming electricity generating unit regulations. The industrial boiler regulations, if applied to electricity generating units, would likely require significant additions of control equipment. If required, such additions would result in material costs of compliance for our generation units, including capital expenditures to install new control equipment and higher operating costs, resulting in material adverse effects on our financial condition, liquidity and results of operations. See Note 7 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010, “Litigation Related to Generation Facilities.”

SO₂ reductions required under the proposed regional haze/visibility rule (or so-called BART rule) only apply to units built between 1962 and 1977. The reductions are required on a unit-by-unit basis. The EPA provides the option for states to use CAIR to satisfy BART reductions for electricity generating units, and Texas has chosen this option. We believe the D.C. Circuit Court decision to leave CAIR in place while the EPA revises it should allow Texas to move forward with its plans.

In connection with our construction of three new lignite-fueled generation units in Texas, we have committed to reduce emissions of NO_x, SO₂ and mercury through the installation of emissions control equipment at both new and existing units and fuel blending at some existing units. We have also applied with the TCEQ to seek a “maximum achievable control technology” determination for our two Oak Grove units recently achieved substantial completion (as defined in the EPC agreements for the units) and have agreed to offset any emissions above those levels. 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 our existing and new coal-fueled generation plants to help meet the offset and reduction commitment:

• To reduce NO_x emissions, we have applied for permits to install selective catalytic reduction (SCR) systems at our Martin Lake plant. In addition, we have installed selective non-catalytic reduction systems at our Monticello and Big Brown plants and improved the low-NO_x burner technology at one of our Monticello units. These activities are in addition to SCR systems being installed at the legacy Sandow unit and at the new Oak Grove units;

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• To reduce mercury emissions, we plan to use activated carbon injection, a sorbent injection system technology, at all of our plants, and

• To reduce SO₂ emissions, we plan to increase use of lower-sulfur coal at various plants. In addition, Martin Lake mine is using coal-cleaning technology to reduce both SO₂ and mercury emissions, and we are evaluating the effectiveness of this technology at Big Brown and Monticello mines.

The Clean Air Act requires each state to monitor air quality for compliance with federal health standards. The EPA is required to periodically review, and if appropriate, revise all national ambient quality standards. The standards for ozone are not being achieved in several areas of Texas. The TCEQ adopted State Implementation Plan (SIP) rules in May 2007 to deal with eight-hour ozone standards, which required nitrogen oxide emission reductions from certain of our peaking natural gas-fueled units in the Dallas-Fort Worth area. In March 2008, the EPA made the eight-hour ozone standards more stringent. In January 2010, the EPA proposed to further reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. Since the EPA projects that SIP rules to address attainment of these new more stringent standards will not be required until December 2013, we cannot yet predict the impact of this action on our generation facilities. In January 2010, the EPA added a new one-hour nitrogen oxide National Ambient Air Quality standard that may require actions within Texas to reduce emissions. The TCEQ will be required to revise its monitoring network and submit an implementation plan with compliance required by January 2021/2022. In June 2010, the EPA adopted a new one-hour sulfur dioxide national ambient air quality standard that may require action within Texas to reduce sulfur dioxide emissions. The TCEQ will be required to conduct modeling and develop an implementation plan by 2014, pursuant to which compliance will be required by 2017, according to the EPA’s implementation timeline. We cannot predict the impact of the new standards on our business, results of operations or financial condition until the TCEQ adopts (if required) an implementation plan with respect to the standards. If the TCEQ adopts implementation plans that require us to install additional emissions controls, or if the EPA adopts more stringent requirements through any of the number of potential rulemaking activities in which it is or may be engaged, we could incur material capital expenditures and higher operating costs, resulting in material adverse effects on our financial condition, liquidity and results of operations.

In October 2010, the EPA proposed to retroactively disapprove a portion of the SIP pursuant to which the state implements its program to achieve the EPA’s National Ambient Air Quality Standards (NAAQS) under the Clean Air Act. In particular, the EPA proposes to retroactively disapprove certain standard permits for pollution control projects that the TCEQ adopted approximately 10 years ago. The EPA asserts that we hold such standard permits for two generation facilities (Big Brown and Stryker Creek). We are investigating the basis for the EPA’s assertion. The EPA has proposed to disapprove this portion of the SIP while acknowledging that emissions covered by these standard permits do not threaten attainment or maintenance of the NAAQS under the Clean Air Act. We believe the TCEQ’s adoption of the standard permit was consistent with the Clean Air Act. However, we cannot predict whether the EPA will take final action to disapprove this portion of the SIP. If the EPA takes final disapproval action, and if that causes us to undertake additional permitting activity and install additional emissions control equipment at our affected generation facilities, we could incur material capital expenditures, resulting in material adverse effects on our financial condition, liquidity and results of operations.

We believe that we hold all required emissions permits for facilities in operation and have 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. We believe our facilities are presently in material compliance with applicable state and federal requirements relating to discharge of pollutants into water. We believe we hold all required waste water discharge permits from the TCEQ for facilities in operation and have applied for or obtained necessary permits for facilities under construction. We also believe we can satisfy the requirements necessary to obtain any required permits or renewals. Recent changes to federal rules pertaining to the Spill Prevention, Control and Countermeasure (SPCC) plans for oil-filled electrical equipment and bulk storage facilities for oil required updating of certain of our facilities. We have developed and implemented SPCC plans as required for those substations, work centers and distribution systems, and we are currently in compliance with the new rules that become effective in November 2011.

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Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQ and the EPA. We believe we possess all necessary permits for these activities from the TCEQ for our present operations. We have obtained the necessary water rights permit from the TCEQ for the lignite mine that supports the Oak Grove units. Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities were published by the EPA in 2004. As prescribed in the regulations, we began implementing a monitoring program to determine the future actions that might need to be taken to comply with these regulations. In January 2007, a federal court ruled against the EPA in a lawsuit brought by environmental groups challenging aspects of these regulations, and in July 2007, the EPA announced that it was suspending the regulations pending further rulemaking. The U.S. Supreme Court issued a decision in April 2009 reversing the federal court’s decision, in part, and finding that the EPA permissibly used cost-benefit analysis in the Section 316(b) regulations. In the absence of regulations, the EPA has instructed the states implementing the Section 316(b) program to use best professional judgment in reviewing applications and issuing permits under Section 316(b). We cannot predict the impact on our operations of the suspended regulations or of new regulations, if any, that replace them.

Radioactive Waste — We currently ship low-level waste material to a disposal facility outside of Texas. Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the State of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. The State of Texas has agreed to a compact for a disposal facility that would be located in Texas. That compact was ratified by Congress and signed by the President in 1998. In 2003, the State of Texas enacted legislation allowing a private entity to be licensed to accept low-level radioactive waste for disposal, and in 2004 the State received a license application from such an entity for review. In January 2009, the TCEQ approved this permit. We expect to continue to ship low-level waste material off-site for as long as an alternative disposal site is available. Should existing off-site disposal become unavailable, the low-level waste material will be stored on-site. (See discussion under “Luminant — Nuclear Generation Operations” above.)

We believe that our on-site used nuclear fuel storage capability is sufficient for a minimum of three 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. Current on-site used nuclear fuel storage capability will require the use of the industry technique of dry cask storage within the next three years.

Solid Waste, Including Fly Ash Associated with Lignite/Coal-Fueled Generation — Treatment, storage and disposal of solid waste and hazardous waste are regulated at the state level under the Texas Solid Waste Disposal Act and at the federal level under the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act. The EPA has issued regulations under the Resource Conservation and Recovery Act of 1976 and the Toxic Substances Control Act, and the TCEQ has issued regulations under the Texas Solid Waste Disposal Act applicable to our facilities. We believe we are in material compliance with all applicable solid waste rules and regulations. In addition, we have registered solid waste disposal sites and have obtained or applied for permits required by such regulations.

In December 2008, an ash impoundment facility at a Tennessee Valley Authority (TVA) site ruptured, releasing a significant quantity of coal ash slurry. No impoundment failures of this magnitude have ever occurred at any of our impoundments, which are significantly smaller than TVA’s and are inspected on a regular basis. We routinely sample groundwater monitoring wells to ensure compliance with all applicable regulations. As a result of the TVA ash impoundment failure, in May 2010, the EPA released a proposed rule that considers regulating coal combustion residuals as either a hazardous waste or a non-hazardous waste. We are unable to predict the requirements of a final rule; however, the potential cost of compliance could be material.

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The EPA issued a notice in December 2009 that it had identified several industries, including the electric power industry, that should be subject to financial responsibility requirements under the Comprehensive Environmental Response, Compensation and Liability Act consistent with the risk associated with their production, transportation, treatment, storage or disposal of hazardous substances. The EPA indicated in its notice that it would develop regulations that define the scope of those financial responsibility requirements. We do not know, at this time, the scope of these requirements, nor are we able to estimate the potential cost (which could be material) of complying with any such new requirements.

Environmental Capital Expenditures

Capital expenditures for our environmental projects totaled $149 million in 2009 and are expected to total approximately $80 million in 2010, consisting primarily of environmental projects at existing lignite/coal-fueled generation plants. These amounts are exclusive of emissions control equipment investment planned as part of the three-unit generation development program, which is expected to total up to $500 million over the construction period. See discussion above under “Luminant — Lignite/Coal-Fueled Generation Operations” regarding planned investments in emissions control systems.

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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 (1)(4)	45	2008	Arcilia C. Acosta has served as a Director of EFH Corp. since May 2008. During the last five years, Ms. Acosta’s principal occupation and employment has been serving as the CEO of CARCON Industries & Construction, L.L.C. (CARCON) and its subsidiaries. She is also the CEO and controlling principal of Southwestern Testing Laboratories, L.L.C. (STL). CARCON’s principal business is commercial, institutional and transportation construction. STL’s principal business is geotechnical engineering, construction materials testing and environmental consulting. Ms. Acosta is a former Chair of the State of Texas Hispanic chambers organization known as the Texas Association of Mexican American Chambers of Commerce (TAMACC) and the Greater Dallas Hispanic Chamber of Commerce. Ms. Acosta serves on the Board of Advisors for Compass Bank and the Board of Governors for the Dallas Foundation.
David Bonderman	68	2007	David Bonderman has served as a Director of EFH Corp. since October 2007. He is a founding partner of TPG Capital, L.P. (TPG). Before forming TPG in 1992, Mr. Bonderman was Chief Operating Officer of the Robert M. Bass Group (now doing business as Keystone Group L.P.) in Fort Worth, Texas. He serves on the boards of the following public companies: Armstrong World Industries, Inc., CoStar Group, Inc., Gemalto N.V., General Motors Company, Harrahs’s Entertainment, RyanAir Holdings PLC, for which he serves as Chairman of the Board, and Univision Communications, Inc. During the past five years, Mr. Bonderman also served on the boards of Burger King Holdings, Inc., Ducati Motor Holding S.P.A., Gemplus International S.A. (predecessor to Gemalto N.V.), IASIS Healthcare Corporation, Korea First Bank Ltd., Mobilcom AG, and Washington Mutual, Inc.
Donald L. Evans (2)(3)(4)	64	2007	Donald L. Evans has served as a Director and Non-Executive Chairman of EFH Corp. since October 2007. He was CEO of the Financial Services Forum from 2005 to 2007, after serving as the 34th secretary of the U.S. Department of Commerce. Before serving as Secretary of Commerce, Mr. Evans was the former CEO of Tom Brown, Inc., a large independent energy company. He also previously served as a member and chairman of the Board of Regents of the University of Texas System. Mr. Evans is also a Senior Partner at Quintana Energy Partners, L.P.

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Name	Age	Served As Director Since	Business Experience
Thomas D. Ferguson (3)	56	2008	Thomas D. Ferguson has served as a Director of EFH Corp. since December 2008. He is a Managing Director of Goldman, Sachs & Co., having joined the firm in 2003. Mr. Ferguson heads the asset management efforts for the merchant bank’s infrastructure investment activity worldwide. He currently serves on the boards of some of Goldman, Sachs & Co.’s largest infrastructure investments, including Associated British Ports, the largest port company in the UK; Carrix, one of the largest private container terminal operators in the world; and Red de Carreteras, a major toll road concessionaire in Mexico. Additional responsibilities at Goldman, Sachs & Co. include an 18 month stint as the CEO of National Golf/American Golf, one of the leading owner/operators of golf courses in the U.S. for which he now serves as the company’s non-executive Chairman.
Frederick M. Goltz (2)(3)	39	2007	Frederick M. Goltz has served as a Director of EFH Corp. since October 2007. He has been with Kohlberg Kravis Roberts and Co., L.P. (KKR) for 14 years. Mr. Goltz has played a significant role in the development of many of the themes pursued by KKR in the energy space, including those related to integrated utilities, merchant generation, and oil and gas exploration and production. He now heads KKR’s newly created Mezzanine Fund headquartered in San Francisco. He is a director of EFCH, TCEH, and Luminant. During the past five years, Mr. Goltz also served on the boards of Accuride Corp. and Texas Genco Holdings, Inc.
James R. Huffines (1)(3)	59	2007	James R. Huffines has served as a Director of EFH Corp. since October 2007. He is Chairman of the University of Texas System Board of Regents, after previously serving as Vice Chairman from November 2007 to April 2009 and Chairman from June 2004 to November 2007. He also is Chairman, Central and South Texas Region, of PlainsCapital Bank, Senior Executive Vice President of PlainsCapital Corporation, and a director of Andrew Harper Travel Publications, Inc. and PlainsCapital Bank.
Scott Lebovitz	35	2007	Scott Lebovitz has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He joined Goldman, Sachs & Co. in 1997 and was promoted to Managing Director in 2007. Mr. Lebovitz serves on the boards of both public and private companies, including CVR Energy, Inc., EFCH, TCEH, and Luminant.

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Name	Age	Served As Director Since	Business Experience
Jeffrey Liaw	33	2007	Jeffrey Liaw has served as a Director of EFH Corp. since October 2007. He is active in TPG’s energy and industrial investing practice areas. Before joining TPG in 2005, he worked for Bain Capital in its industrials practice. Mr. Liaw serves on the boards of both public and private companies, including Graphic Packaging Holding Company and Oncor.
Marc S. Lipschultz (2)(4)	41	2007	Marc S. Lipschultz has served as a Director of EFH Corp. since October 2007. He joined KKR in 1995 and is the global head of KKR’s Energy and Infrastructure business. Mr. Lipschultz serves on KKR’s Management Committee and its Infrastructure Investment Committee. Currently, he is on the boards of Accel-KKR Company and Oncor. During the past five years, Mr. Lipschultz also served on the boards of Texas Genco Holdings, Inc. and The Boyds Collection, Ltd.
Michael MacDougall (2)(3)	40	2007	Michael MacDougall has served as a Director of EFH Corp. since October 2007. He is a partner of TPG. Prior to joining TPG in 2002, Mr. MacDougall was a vice president in the Principal Investment Area of the Merchant Banking Division of Goldman, Sachs & Co., where he focused on private equity and mezzanine investments. Mr. MacDougall serves on the board of directors of both public and private companies, including Graphic Packaging Holding Company, Kraton Performance Polymers Inc., Valerus Compression Services, L.P., EFCH, TCEH, and Luminant. During the past five years, he also served on the board of Aleris International. Mr. MacDougall also serves as the Chairman of the Board of The Opportunity Network and is a member of the Board of the Dwight School Foundation and Islesboro Affordable Property.
Lyndon L. Olson, Jr. (3)	63	2007	Lyndon L. Olson, Jr. has served as a Director of EFH Corp. since October 2007. He was a Senior Advisor with Citigroup Inc. from 2002 to 2008, after serving as United States Ambassador to Sweden from 1998 to 2001. He previously was affiliated with Citigroup from 1990 to 1998, as President and CEO of Travelers Insurance Holdings and the Associated Madison Companies, predecessor companies. Before joining Citigroup, he had been President of the National Group Corporation and CEO of its National Group Insurance Company. Ambassador Olson also is a former Chairman and a Member of the Texas 173 State Board of Insurance, former President of the National Association of Insurance Commissioners, and a former member of the Texas House of Representatives. Ambassador Olson also serves on the board of First Acceptance Corporation, Sammons Enterprises and Texas Meter and Device Company.

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Name	Age	Served As Director Since	Business Experience
Kenneth Pontarelli (2)(4)	40	2007	Kenneth Pontarelli has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He transferred to the Principal Investment Area in 1999 and was promoted to Managing Director in 2004. Mr. Pontarelli serves as a director of both public and private companies, including CCS, Inc., Cobalt International Energy, L.P., Expro International Group Ltd., CVR Energy, Inc., Kinder Morgan, Inc. and TXU Energy.
William K. Reilly	70	2007	William K. Reilly has served as a Director of EFH Corp. since October 2007. He is a Senior Advisor to TPG and a founding partner of Aqua International Partners, an investment group that invests in companies that serve the water and renewable energy sectors. Mr. Reilly previously served as the seventh Administrator of the EPA. 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. During the past five years, he also served on the board of Ionics Inc. Before serving as EPA Administrator, Mr. Reilly was President of World Wildlife Fund and President of The Conservation Foundation. He previously served as Executive Director of the Rockefeller Task Force on Land Use and Urban Growth, a senior staff member of the President’s Council on Environmental Quality, 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	38	2007	Jonathan D. Smidt has served as a Director of EFH Corp. since October 2007. He has been with KKR since 2000, where he is a member of the firm’s Energy and Natural Resources industry team. Currently, he is a director of Laureate Education Inc., East Resources Inc. and TXU Energy.
John F. Young (2)(3)	54	2008	John F. Young has served as a Director and President and Chief Executive of EFH Corp. since January 2008. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon from March 2003 to January 2008 including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation. Mr. Young is also a director of Luminant.

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Name	Age		Served As Director Since		Business Experience
Kneeland Youngblood (1)		55		2007	Kneeland Youngblood has served as a Director of EFH Corp. since October 2007. He is a founding partner of Pharos Capital Group, a private equity firm that focuses on providing growth and expansion capital to businesses in technology, business services, and health care services. Mr. Youngblood is a director of the following public companies: Starwood Hotels and Resorts Worldwide, Inc., Gap Inc. and Burger King Holdings, Inc. Mr. Youngblood is a member of the Council on Foreign Relations.

(1) Member of Audit Committee.

(2) Member of Executive Committee.

(3) Member of Governance and Public Affairs Committee

(4) Member of Organization and Compensation Committee

Director Qualifications

In October 2007, David Bonderman, Donald L. Evans, Frederick M. Goltz, James R. Huffines, Scott Lebovitz, Jeffrey Liaw, Marc S. Lipschultz, Michael MacDougall, Lyndon L. Olson, Jr., Kenneth Pontarelli, William K. Reilly, Jonathan D. Smidt, and Kneeland Youngblood were elected to EFH Corp.’s board of directors (the “Board”). Arcilia C. Acosta, Thomas D. Ferguson and John F. Young joined the Board in 2008. Messrs. Bonderman, Ferguson, Goltz, Lebovitz, Liaw, Lipschultz, MacDougall, Pontarelli, and Smidt are collectively referred to as the “Sponsor Directors.” Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly, Young, and Youngblood are collectively referred to as the “Non-Sponsor Directors.”

Each of the Sponsor Directors was elected to the Board pursuant to the Limited Partnership Agreement of Texas Energy Future Holdings Limited Partnership, the holder of a majority of the outstanding capital stock of the Company. Pursuant to such agreement, Messrs. Goltz, Lipschultz and Smidt were appointed to the Board as a consequence of their relationships with Kohlberg Kravis Roberts & Co.; Messrs. Bonderman, Liaw and MacDougall were appointed to the Board as a consequence of their relationships with TPG Capital, L.P., and Messrs. Ferguson, Lebovitz and Pontarelli were appointed to the Board as a consequence of their relationships with GS Capital Partners.

When considering whether the Board’s directors and nominees have the experience, qualifications, attributes and skills, taken as a whole, to enable the Board to satisfy its oversight responsibilities effectively in light of EFH Corp.’s business and structure, the Board focused primarily on the information in each of the Board member’s or nominee’s biographical information set forth on the pages above. In addition, EFH Corp. believes that each of its directors possesses high ethical standards, acts with integrity, and exercises careful judgment. Each is committed to employing his/her skills and abilities in the long-term interests of EFH Corp and its stakeholders. Finally, our directors are knowledgeable and experienced in business, governmental, and civic endeavors, further qualifying them for service as members of the Board.

The Sponsor Directors possess experience in owning and managing privately held enterprises and are familiar with corporate finance and strategic business planning activities of highly-leveraged companies such as EFH Corp. Some of the Sponsor Directors also have experience advising and overseeing the operations of large industrial, manufacturing or retail companies similar to our businesses. Finally, several of the Sponsor Directors possess substantial expertise in advising and managing companies in segments of energy industry, including, among others, power generation, oil and gas, and energy infrastructure and transportation.

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As a group and individually, the Non-Sponsor Directors possess extensive experience in governmental and civic endeavors and in the business community, in each case, in the markets where our businesses operate.

Mr. Young’s employment agreement provides that he will serve as a member of the Board during the time he is employed by the Company. Before joining the Company as President and Chief Executive Officer, he held various senior management positions at other companies in the energy industry over twenty years, including, most recently, his role as Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation.

Ms. Acosta manages the operations of a large commercial construction company in Texas and has significant experience within the local Hispanic business community, having served as the chair of the Greater Dallas Hispanic Chamber of Commerce and the Texas Association of Mexican American Chambers of Commerce. Mr. Evans has demonstrated ability and achievement in both the private and public sectors, serving as U.S. Secretary of Commerce during the Bush Administration, and both before and after his government service, acting as Chairman and Chief Executive Officer of a publicly-owned energy company, Tom Brown, Inc. Mr. Huffines has demonstrated achievement in both business and academic endeavors, and, given his employment in various senior management positions in the banking industry, has sufficient experience and expertise in financial matters to qualify him to serve as EFH Corp.’s “audit committee financial expert.” Mr. Olson possesses substantial experience in both federal and state government through, among other things, his service as the former U.S. Ambassador to Sweden and as a former member of the Texas House of Representatives, and has advised and overseen the operations of large companies, in particular his service in the insurance industry. Mr. Reilly possesses a distinguished record of public service and extensive policy-making experience as a former administrator of the EPA, lectures extensively on environmental issues facing companies operating in the energy industry and currently serves as Co-Chairman of the National Commission on Energy Policy. Mr. Youngblood has served on numerous boards for large public companies, has extensive experience managing and advising companies in his capacity as a partner in a private equity firm (not affiliated with the Sponsor Group), is highly knowledgeable of federal and state political matters, and has served on the board of directors of the United States Enrichment Corporation, a company that contracts with the U.S. Department of Energy to produce enriched uranium for use in nuclear power plants.

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Executive Officers

The names and information regarding EFH Corp.’s executive officers are set forth below:

Name of Officer	Age	Positions and Offices Presently Held	Date First Elected to Present Offices	Business Experience (Preceding Five Years)
John F. Young	54	President and Chief Executive Officer of EFH Corp.	January 2008	John F. Young was elected President and Chief Executive Officer of EFH Corp. in January 2008. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon Corporation from March 2003 to January 2008, including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation.
James A. Burke	42	President and Chief Executive of TXU Energy	August 2005	James A. Burke was elected President and Chief Executive of TXU Energy in August 2005. Previously, Mr. Burke was Senior Vice President Consumer Markets of TXU Energy.
David A. Campbell	42	President and Chief Executive of Luminant	June 2008	David A. Campbell was elected President and Chief Executive of Luminant in June 2008. Mr. Campbell was Executive Vice President and Chief Financial Officer of EFH Corp. from April 2007 to June 2008 having previously served as Acting Chief Financial Officer beginning in March 2006 and as Executive Vice President for Corporate Planning, Strategy & Risk when he joined the company in May 2004.

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Name of Officer	Age	Positions and Offices Presently Held	Date First Elected to Present Offices	Business Experience
Charles R. Enze	57	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.
Joel D. Kaplan	41	Executive Vice President of EFH Corp.	November 2009	Joel D. Kaplan was elected Executive Vice President of EFH Corp. in November 2009 and oversees the company’s public affairs organization. Prior to joining EFH Corp., Mr. Kaplan served as Deputy Chief of Staff in the George W. Bush White House from 2006 to 2008 and Deputy Director of the Office of Management and Budget from 2003 to 2006.
Paul M. Keglevic	56	Executive Vice President and Chief Financial Officer of EFH Corp.	July 2008	Paul M. Keglevic was elected Executive Vice President and Chief Financial Officer of EFH Corp. in July 2008. Before joining EFH Corp., he was an audit partner at PricewaterhouseCoopers. Mr. Keglevic was PricewaterhouseCoopers’ Utility Sector Leader from 2002 to 2008 and Clients and Sector Assurance Leader from 2007 to 2008.
Richard J. Landy	64	Executive Vice President of EFH Corp.	February 2010	Richard J. Landy was elected Executive Vice President of EFH Corp. in February 2010 and oversees human resources. Prior to joining EFH Corp., Mr. Landy was owner and consultant of Richard J. Landy, LLC from 2007 to 2009 and Senior Vice President of Exelon from 2002 to 2007.

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Name of Officer	Age	Positions and Offices Presently Held	Date First Elected to Present Offices	Business Experience
M. A. McFarland	41	Executive Vice President and Chief Commercial Officer of Luminant and Executive Vice President of EFH Corp.	July 2008	M. A. McFarland was elected Executive Vice President and Chief Commercial Officer of Luminant and Executive Vice President of EFH Corp. in July 2008. Before joining Luminant, Mr. McFarland served as Senior Vice President of Mergers, Acquisitions and Divestitures and as a Vice President in the wholesale marketing and trading division power team at Exelon.
Robert C. Walters	52	Executive Vice President and General Counsel of EFH Corp.	March 2008	Robert C. Walters was elected Executive Vice President and General Counsel of EFH Corp. in March 2008. Prior to joining EFH Corp., Mr. Walters was a Partner of Vinson & Elkins LLP and served on the firm’s management committee. Mr. Walters was co-managing partner of the Dallas office of Vinson & Elkins LLP from 1998 through 2005. Mr. Walters will resign from EFH Corp. effective during the first quarter of 2011.

There is no family relationship between any of the above-named executive officers.

Audit Committee Financial Expert

The Board has determined that James R. Huffines is an “Audit Committee Financial Expert” as defined in Item 407(d)(5) of SEC Regulation S-K.

Code of Conduct

EFH Corp. maintains certain corporate governance documents on EFH Corp’s website at www.energyfutureholdings.com. EFH Corp.’s Code of Conduct can be accessed by selecting “Investor Relations” on the EFH Corp. website. EFH Corp.’s Code of Conduct applies to all of its employees, officers (including the Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer) and directors. Any amendments to the Code of Conduct will be posted on EFH Corp.’s website. Printed copies of the corporate governance documents that are posted on EFH Corp.’s website are also available to any investor upon request to the Secretary of EFH Corp. at 1601 Bryan Street, Dallas, Texas 75201-3411.

Procedures for Shareholders to Nominate Directors; Arrangement to Serve as Directors

The Amended and Restated Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC, the general partner of Texas Holdings, generally requires that the members of Texas Energy Future Capital Holdings LLC take all necessary action to ensure that the persons who serve as its managers also serve on the EFH Corp. Board. In addition, Mr. Young’s employment agreement provides that he will continue to serve as a member of the Board during the time he is employed by EFH Corp.

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Because of these requirements, together with Texas Holdings’ controlling ownership of EFH Corp.’s outstanding common stock, there is no policy or procedure with respect to shareholder recommendations for nominees to the EFH Corp. Board.

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EXECUTIVE COMPENSATION

Organization and Compensation Committee

The Organization and Compensation Committee (the “O&C Committee”) of EFH Corp.’s Board of Directors (the “Board”) is comprised of four non-employee directors: Arcilia C. Acosta, Donald L. Evans, Marc S. Lipschultz and Kenneth Pontarelli. The primary responsibility of the O&C Committee is to:

• determine and oversee the compensation program of EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities), including making recommendations to the Board with respect to the adoption, amendment or termination of compensation and benefits plans, arrangements, policies and practices;

• evaluate the performance of EFH Corp.’s Chief Executive Officer (the “CEO”) and the other executive officers of EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities) (collectively, the “executive officers”), including all of the executive officers named in the Summary Compensation Table (the “Named Executive Officers”), and

• approve executive compensation based on those evaluations.

Compensation Discussion and Analysis

Compensation of the CEO

In determining the compensation of the CEO, the O&C Committee annually follows a thorough and detailed process. At the end of each year, the O&C Committee reviews a self-assessment prepared by the CEO regarding his performance and the performance of our businesses and meets (with and without the CEO) to evaluate and discuss his performance and the performance of our businesses.

In addition to conducting an annual review of the CEO’s performance, the O&C Committee periodically uses independent compensation consultants to assess the compensation of the CEO against a variety of market reference points and competitive data, including the compensation practices of a number of companies that we consider to comprise our peer group, size-adjusted energy services industry survey data and size-adjusted general industry survey data. While the O&C Committee tries to ensure that the bulk of the CEO’s compensation is directly linked to his performance and the performance of our businesses, the O&C Committee also seeks to set his compensation in the manner that is competitive for retention purposes. The last assessment of the CEO’s compensation was performed in late 2009 / early 2010, when the O&C Committee engaged Towers Watson to perform a competitive analysis of the CEO’s compensation. In January 2010, Towers Watson delivered its report to the O&C Committee, which report included market data for a peer group composed of the following companies:

AES Corporation	Allegheny Energy, Inc.	Ameren Corp.
American Electric Power Co. Inc,	Calpine Corp.	Constellation Energy Group Inc.
Dominion Resources Inc.	Duke Energy Corp.	Edison International
Entergy Corp.	Exelon Corp.	FirstEnergy Corp.
FPL Group Inc.	Mirant Corp.	NRG Energy, Inc.
PPL Corp.	Progress Energy Inc.	Public Service Enterprise Group Inc.
RRI Energy Inc.	Southern Co.	Xcel Energy Inc.

The data for CEO compensation of the peer group was developed at both the 50th and 75th percentiles of market in order to provide the O&C Committee with a broad market view and multiple benchmarks. The O&C Committee targets total direct compensation around the 75th percentile of the peer group.

While the O&C Committee considers market reference points and competitive data in determining the appropriate compensation of the CEO (and the other executive officers), the O&C Committee also considers qualitative and subjective factors that are more specific to EFH Corp. in making such determinations. One such factor is the fact that EFH Corp. is a highly-leveraged, privately-owned company. In this regard, while executive officers of publicly traded energy companies, including those in our peer group, are typically granted smaller long-term equity incentive awards on an annual basis, our executive officers received one-time, up front grants of long-term equity incentive awards intended to cover a multi-year period. Extended periods of economic strength or weakness generally has less affect on the cumulative value of annual awards as compared to one-time, up front awards because the annual awards are typically granted at fair market value over time. Accordingly, one-time, up front awards are typically riskier than annual awards.

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After a comprehensive review of the CEO’s performance and the performance of our businesses in 2009, and taking into consideration the Towers Watson report, the economic dislocation occurring over the last 18 months and other qualitative and subjective factors as described above, the O&C Committee approved several changes to the compensation arrangement for the CEO in February 2010. The O&C Committee made these changes to provide incentives for retention and performance and to maintain a strong alignment between the CEO and our shareholders. We believe these changes are consistent with our compensation philosophy as described below.

Compensation of Other Executive Officers

In determining whether to make any adjustments to the compensation of any of our executive officers (other than the CEO), the O&C Committee seeks the input of the CEO. At the end of each year, the CEO reviews a self-assessment prepared by each of these executive officers and assesses the executive officer’s performance against business unit and individual goals and objectives. The O&C Committee and the CEO then review the CEO’s assessments and, in that context, the O&C Committee approves any adjustments to the compensation for each of these executive officers.

In addition to these annual reviews/assessments, the CEO periodically assesses the compensation of each of these executive officers. The last assessment of the compensation of the executive officers by the CEO was performed in the second half of 2009. Following that assessment, and taking into consideration the economic dislocation occurring over the last 18 months and other qualitative and subjective factors as described above, the CEO suggested several changes to the compensation arrangements for certain of our executive officers in order to provide incentives for retention and performance and to maintain alignment between our executive officers and shareholders. These changes, which are described in more detail below, were approved by the O&C Committee in October 2009 with respect to such executive officers, including each of Messrs. Keglevic, Campbell, Walters and Burke. We believe these changes are consistent with our compensation philosophy as described below.

Compensation Philosophy

We have a pay-for-performance compensation philosophy, which places an emphasis on pay-at-risk. In other words, a significant portion of an executive officer’s compensation is comprised of variable, at-risk incentive compensation. Our compensation program is intended to compensate executive officers appropriately for their contribution to the attainment of our financial, operational and strategic objectives. In addition, we believe it is important to retain our executive officers and strongly align their interests with EFH Corp.’s shareholders by emphasizing long-term incentive compensation, including equity-based compensation.

To achieve our compensation philosophy, we believe that:

• compensation plans should balance both long-term and short-term objectives;

• the overall compensation program should emphasize variable compensation elements that have a direct link to overall corporate performance and shareholder value, and

• an executive officer’s individual compensation level should be based upon an evaluation of the financial and operational performance of that executive officer’s business unit as well as the executive officer’s individual performance.

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We believe our compensation philosophy supports our businesses by:

• aligning performance measures with our business objectives to drive the financial and operational performance of EFH Corp. and its business units;

• rewarding business unit and individual performance by providing compensation levels consistent with the level of contribution and degree of accountability;

• attracting and retaining the best performers, and

• strengthening the correlation between the long-term interests of our executive officers and shareholders.

Elements of Compensation

The material elements of our executive compensation program are:

• a base salary;

• the opportunity to earn an annual performance-based cash bonus based on the achievement of specific corporate, business unit and individual performance goals, and

• long-term incentive awards, primarily in the form of (i) long-term cash incentive awards and (ii) options to purchase shares of EFH Corp.’s 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”).

In addition, executive officers generally have the opportunity to participate in certain of our broad-based employee compensation plans, including our Thrift (401(k)) Plan, retirement plans and non-qualified benefit plans, and to receive certain perquisites.

Assessment of Compensation Elements

We design the majority of an executive officer’s compensation to be directly linked to corporate and business unit performance. For example, an executive officer’s annual performance-based cash bonus is primarily based on the achievement of certain corporate and business unit financial and operational targets (such as management EBITDA, cost management, generation output and customer satisfaction). In addition, the vesting of a portion of each executive officer’s Stock Option Awards is contingent upon the attainment of certain management EBITDA targets. We also try to ensure that our executive compensation program is competitive in order to reduce the risk of losing our executive officers.

The following is a detailed discussion of the principal compensation elements provided to our executive officers. More detail about each of the elements can be found in the compensation tables, including the footnotes to the tables, and the narrative discussion following certain of 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 and retain qualified talent.

The O&C Committee annually reviews base salaries and periodically uses independent compensation consultants to ensure the base salaries are market-competitive. The O&C Committee may also review an executive officer’s base salary from time to time during a year, including if the executive officer is given a promotion or if his responsibilities are significantly increased.

We want to ensure our cash compensation is competitive and sufficient to incent executive officers to remain with us, recognizing our high performance expectations across a broad set of operational, financial, customer service and community-oriented goals and objectives and the higher risk levels associated with being a significantly-leveraged company.

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In light of the significant market dislocation and uncertainty that began in late 2008 and continued into 2009, our Named Executive Officers’ base salaries for 2009 remained unchanged from 2008 levels. In October 2009, the O&C Committee approved an increase in the base salary, effective January 1, 2010, for each of the Named Executive Officers, with the exception of Messrs. Young and Burke. In February 2010, the O&C Committee approved an increase in the base salary of each of Messrs. Young and Burke, which increases took effect retroactively on January 1, 2010. These increases reflect, in part, that none of the Named Executive Officers received a salary increase for 2009. The following table indicates the Named Executive Officers’ base salaries for 2008, 2009 and 2010.

Name	Title	2008 Base Salary		2009 Base Salary		Approved 2010 Base Salary
John F. Young	President and Chief Executive Officer of EFH Corp.	$	1,000,000	$	1,000,000	$	1,200,000
Paul M. Keglevic	Executive Vice President and Chief Financial Officer of EFH Corp.	$	600,000	$	600,000	$	650,000
David A. Campbell	Chief Executive Officer of Luminant	$	600,000	$	600,000	$	700,000
Robert C. Walters	Executive Vice President and General Counsel of EFH Corp.	$	575,000	$	575,000	$	600,000
James A. Burke	Chief Executive Officer of TXU Energy	$	600,000	$	600,000	$	630,000
Rizwan Chand (1)	Former Executive Vice President — Human Resources of EFH Corp.	$	450,000	$	450,000		N/A

(1) Mr. Chand’s employment with EFH Corp. terminated in October 2009.

Annual Performance-Based Cash Bonus — Executive Annual Incentive Plan

The Executive Annual Incentive Plan (“EAIP”) provides an annual performance-based cash bonus for the successful attainment of certain annual financial and operational performance targets that are established annually at each of the corporate and business unit levels by the O&C Committee. Under the terms of the EAIP, performance against these targets, which are generally set at challenging levels to incent high performance, drives bonus funding. Based on the level of attainment of these performance targets, an aggregate EAIP funding percentage amount for all participants is determined.

Our financial performance targets typically include “management” EBITDA, a non-GAAP financial measure. When the O&C Committee reviews management EBITDA for purposes of determining our performance against the applicable management EBITDA target, it includes our earnings before interest, taxes, depreciation and amortization plus transaction, management and/or similar fees paid to the Sponsor Group, together with such adjustments as the O&C Committee shall determine appropriate in its discretion after good faith consultation with the CEO and the Chief Financial Officer, including adjustments consistent with those included in the comparable definitions in the TCEH Senior Secured Facilities (to the extent considered appropriate for executive compensation purposes). Our management 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 our financial plan (the “Financial Plan”). The management EBITDA targets are intended to measure achievement of the Financial Plan and the adjustments to management EBITDA described above primarily represent elements of our performance that are either beyond the control of management or were not predictable at the time the Financial Plan was submitted. The O&C Committee has broad authority to make these or any other adjustments to EBITDA that it deems appropriate in connection with its evaluation and compensation of our executive officers. Management EBITDA is an internal measure used only for performance management purposes, and EFH Corp. does not intend for management EBITDA to be an alternative to any measure of financial performance presented in accordance with GAAP. Management EBITDA is not the same as Adjusted EBITDA, which is disclosed elsewhere in this prospectus and defined in the glossary to this prospectus.

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Financial and Operational Performance Targets

The following table provides a summary of the performance targets for Mr. Young, who had primary responsibility at EFH Corp.

Performance Targets — EFH Corp.	Weight			Performance (1)			Payout
EFH Corp. Management EBITDA		50	%		101	%		50	%
EFH Corp. Management EBITDA (excluding Oncor)		10	%		119	%		12	%
Luminant Scorecard Multiplier (see below)		10	%		119	%		12	%
TXU Energy Scorecard Multiplier (see below)		10	%		141	%		14	%
EFH Corp. Total Spend		10	%		121	%		12	%
EFH Business Services Cost		10	%		130	%		13	%
Total		100	%					113	%

(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

The following table provides a summary of the performance targets for Messrs. Keglevic and Walters, who had primary responsibility at EFH Corp. and EFH Business Services.

Performance Targets — EFH Corp./Services	Weight			Performance (1)			Payout
EFH Corp. Management EBITDA (excluding Oncor)		60	%		119	%		72	%
Luminant Scorecard Multiplier (see below)		10	%		119	%		12	%
TXU Energy Scorecard Multiplier (see below)		10	%		141	%		14	%
EFH Corp. Total Spend		10	%		121	%		12	%
EFH Business Services Cost		10	%		130	%		13	%
Total		100	%					123	%

(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

The following table provides a summary of the performance targets for Mr. Campbell, who had primary responsibility at Luminant.

Performance Targets — Luminant	Weight			Performance (1)			Payout
EFH Corp. Management EBITDA (excluding Oncor)		25	%		119	%		30	%
Luminant Management EBITDA (excluding 3 new units)		30	%		146	%		44	%
Luminant Baseload Generation (excluding 3 new units)		18.75	%		89	%		17	%
Luminant O&M/SG&A/Capital Expenditures		15	%		139	%		21	%
Luminant Fossil Fuel Costs		7.5	%		75	%		5	%
Management EBITDA for 3 new units (excluding capital expenditures)		3.75	%		56	%		2	%
Total		100	%					119	%

(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

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The following table provides a summary of the performance targets for Mr. Burke, who had primary responsibility at TXU Energy.

Performance Targets — TXU Energy	Weight			Performance (1)			Payout
EFH Corp. Management EBITDA (excluding Oncor)		25	%		119	%		30	%
TXU Energy Management EBITDA		26.25	%		200	%		53	%
Contribution Margin		15	%		200	%		30	%
TXU Energy Total Costs		15	%		59	%		9	%
Upgrades to Customer Care System (Project Spend, PUCT Complaints and Days Meter to Cash)		11.25	%		29	%		3	%
Customer Satisfaction		7.5	%		150	%		11	%
Total		100	%					136	%

(1) Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%.

Individual Performance Modifier

After approving the actual performance against the applicable targets under the plan, the O&C Committee and/or the CEO reviews the performance of each of our executive officers on an individual and comparative basis. Based on this review, which includes an analysis of both objective and subjective criteria, including the CEO’s recommendations (with respect to all executive officers other than himself), the O&C Committee approves an individual modifier for each executive officer. Under the terms of the EAIP for 2009, the individual performance modifier can range from an outstanding rating (200%) to an unacceptable rating (0%). In February 2010, the O&C Committee amended the EAIP to reduce the maximum individual performance modifier applicable for 2010 and beyond from 200% to 150%. To calculate an executive officer’s final performance-based cash bonus, the executive officer’s corporate/business unit payout percentages are multiplied by the executive officer’s target incentive level, which is computed as a percentage of annualized base salary, and then by the executive officer’s individual performance modifier.

Actual Award

The following table provides a summary of the 2009 performance-based cash bonus for each Named Executive Officer (other than Mr. Chand) under the EAIP.

Name	Target (% of salary)			Target Award ($ Value)		Actual Award
John F. Young (1)		100	%	$	1,000,000	$	1,469,000
Paul M. Keglevic (2)		75	%	$	450,000	$	664,200
David A. Campbell (3)		75	%	$	450,000	$	642,600
Robert C. Walters (4)		75	%	$	431,250	$	610,000
James A. Burke (5)		75	%	$	450,000	$	856,800

(1) Mr. Young’s incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier that increased his incentive award. In 2009, Mr. Young successfully led the company in a difficult year in which sales volumes and demand fell, wholesale power prices declined and the credit markets were at times inaccessible. Notwithstanding these difficulties, Mr. Young created value in many parts of the company’s businesses. In particular, Mr. Young led the company’s efforts in, among other things: improving operations and safety at our generation and mining operations; participating in the national debate on climate change, green energy and financial reforms; bringing online two new lignite-fueled generation units on time and budget; implementing substantial and lasting cost reductions; exceeding EFH Corp.’s planned EBITDA for 2009; and strengthening the company’s management team. Given these and other significant achievements, the O&C Committee approved an individual performance modifier that increased Mr. Young’s incentive award.

(2) Mr. Keglevic’s incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and EFH Business Services and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier that increased his incentive award. In 2009, Mr. Keglevic successfully implemented several new financial processes at EFH Corp. and its business units, including processes for understanding, managing and communicating the financial and operational performance of our businesses, managing the varied risks of our businesses and preserving effective liquidity levels. In addition, Mr. Keglevic led the company’s liquidity and liability management efforts, including the successful amendment to the TCEH Senior Secured Facilities. Given these significant accomplishments and other achievements (including his installation of a “drive for results” culture), the O&C Committee approved an individual performance modifier that increased Mr. Keglevic’s incentive award.

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(3) Mr. Campbell’s incentive award is based on the successful achievement of a financial performance target for EFH Corp. and the financial and operational performance targets for Luminant and an individual performance modifier that increased his incentive award. In 2009, Mr. Campbell strengthened the Luminant management team (including, among others, the designation of a new Chief Nuclear Officer and Chief Fossil Officer) while overseeing strong financial and operational results primarily at Luminant’s nuclear plant and in Luminant’s wholesale energy organization. Luminant’s baseload generation construction program also achieved several important milestones, including the substantial completion of the two new lignite-fueled units, at costs and time-to-build schedules that are in the top decile relative to recent industry benchmarks. In addition, under Mr. Campbell’s leadership, Luminant had a very strong year for safety, with substantially all of its recordable safety metrics being in the top quartile for its industry. Given these significant accomplishments and other achievements (including his focus on developing strategic business solutions and building a team-oriented culture), the O&C Committee approved an individual performance modifier that increased Mr. Campbell’s incentive award.

(4) Mr. Walters’ incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and EFH Business Services and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier that increased his incentive award. In 2009, Mr. Walters successfully managed several significant legal issues of the company. In particular, Mr. Walters’ led the company’s efforts in (i) defending the challenges to the Oak Grove and Sandow 5 construction and operating permits, (ii) negotiating the termination and transition of the company’s outsourcing relationship with CapGemini Energy and (iii) settling a dispute with the PUCT regarding alleged market manipulation activities. In addition, Mr. Walters drove improvements in the financial performance of our real estate holdings. Given these significant accomplishments and other achievements (including his strategic contributions in the political and civic arena on a local, state and national level), the O&C Committee approved an individual performance modifier that increased Mr. Walters’ incentive award.

(5) Mr. Burke’s incentive award is based on the successful achievement of a financial performance target for EFH Corp. and the financial and operational performance targets for TXU Energy and an individual performance modifier that increased his incentive award. In 2009, Mr. Burke strengthened the TXU Energy management team and performance-oriented culture to drive strong financial and operational results at TXU Energy. Among the operational results, Mr. Burke led the successful implementation of a new customer care system and successfully managed the transition of a number of functions previously performed by Capgemini Energy. Among the financial results, Mr. Burke was successful in driving improvement in retail margins, managing TXU Energy through a challenging economic environment and implementing overall customer satisfaction ratings. Given these significant accomplishments and other achievements (including his continued commitment to build a strong retail and customer-focused culture at TXU Energy), the O&C Committee approved an individual performance modifier that increased Mr. Burke’s incentive award.

In October 2009, the O&C Committee approved an increase in the annual target award under the EAIP from 75% of base salary to 85% of base salary for Messrs. Keglevic, Campbell, Walters and Burke. These increases will be effective for the 2010 award period.

Long-Term Incentive Awards

Long-Term Cash Incentive

In October 2009, the O&C Committee approved the adoption of a new long-term cash incentive (the “LTI”), effective as of the date of adoption, to be included by amendment in the employment agreements of each of Messrs. Keglevic, Campbell, Walters and Burke. Under the terms of the LTI, each of Messrs. Keglevic, Campbell, Walters and Burke will be entitled to receive on September 30, 2012, to the extent such Named Executive Officer remains employed by EFH Corp. on such date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 75% of the aggregate EAIP award received by such executive officer for fiscal years 2009, 2010 and 2011.

In February 2010, the O&C Committee approved the adoption of an LTI to be included by amendment in the employment agreement of Mr. Young. Under the terms of the LTI, Mr. Young will be entitled to receive on September 30, 2012, to the extent Mr. Young remains employed by EFH Corp. on such date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 100% of the aggregate EAIP award received by Mr. Young for fiscal years 2009, 2010 and 2011.

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These awards provide significant retentive value because an award is not paid to an executive officer unless the executive officer remains employed with us until September 30, 2012 (subject to the customary exceptions described above). In addition, these awards provide additional incentive to our executive officers to achieve top operational and financial performance because the award is based on a percentage of the executive officers’ annual performance-based cash bonuses.

Long-Term Equity Incentives

We believe it is important to strongly align the interests of our executive officers and shareholders through equity-based compensation. In December 2007, our Board approved and adopted our 2007 Stock Incentive Plan pursuant to which we grant Stock Option Awards to our executive officers. The purpose of the 2007 Stock Incentive Plan is to:

• promote our long-term financial interests and growth by attracting and retaining management and other personnel with the training, experience and ability to make a substantial contribution to our success;

• motivate management and other personnel by means of growth-related incentives to achieve long-range goals, and

• strengthen the correlation between the long-term interests of our shareholders and the interests of our executive officers through opportunities for stock (or stock-based) ownership in EFH Corp.

The Stock Option Awards granted to our executive officers provide significant retentive value because a portion of these awards is time-based and vest over a five year period. In addition, we believe that the Stock Option Awards granted to our executive officers provide incentive to our executive officers to achieve top operational and financial performance because a portion of these Stock Option Awards is performance-based and only vests upon EFH Corp. achieving certain management EBITDA targets.

In February 2008, Mr. Young was granted 7,500,000 Stock Option Awards. In May 2008, Messrs. Campbell, Walters and Burke were granted 4,000,000, 2,000,000 and 2,450,000 Stock Option Awards, respectively. In December 2008, Mr. Keglevic was granted 2,500,000 Stock Option Awards. Each of these Stock Option Awards are set forth in the table below and are referred to as the “Original Stock Option Awards,” half of which were “Original Time Vested Options” and half of which were “Original Performance Vested Options.” The exercise price of the Original Stock Option Awards (the fair market value on the grant date) is $5.00.

Executive Officer	Original Time Vested Options		Original Performance Vested Options		Exercise Price
John Young		3,750,000		3,750,000	$	5.00
Paul Keglevic		1,250,000		1,250,000	$	5.00
David Campbell		2,000,000		2,000,000	$	5.00
Robert Walters		1,000,000		1,000,000	$	5.00
James Burke		1,225,000		1,225,000	$	5.00

In October 2009 (February 2010, with respect to Mr. Young), the O&C Committee approved the grant of new Stock Option Awards to the Named Executive Officers as set forth in the table below. The new Stock Option Awards are referred to as the “New Stock Option Awards,” a portion of which are “New Time Vested Options” and a portion of which are “New Cliff Vested Options.” In connection with these grants, each Named Executive Officer surrendered to EFH Corp. a portion of his Original Performance Vested Options. The exercise price of the New Stock Option Awards is $3.50.

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Executive Officer	Surrendered Original Performance Vested Options		New Time Vested Options		New Cliff Vested Options		Exercise Price
John Young		1,500,000		1,500,000		1,500,000	$ $	5.00 3.50
Paul Keglevic		500,000		500,000		500,000	$ $	5.00 3.50
David Campbell		800,000		800,000		800,000	$ $	5.00 3.50
Robert Walters		400,000		400,000		400,000	$ $	5.00 3.50
James Burke		490,000		200,000		490,000	$ $	5.00 3.50

Please refer to the outstanding Equity Awards at Fiscal Year-End — 2009 table, including the footnotes thereto, for a summary of the outstanding Stock Option Awards held by each of the Named Executive Officers.

The Stock Option Awards vest (subject to the executive officer continuing to be employed by EFH Corp.) as follows:

• Time Vested Options

• The Original Time Vested Options and the New Time Vested Options vest in 20% increments on each of the first five anniversaries of September 30, 2007 and September 30, 2009, respectively.

• The New Cliff Vested Options vest 100% on September 30, 2014.

• Performance Vested Options

• The Original Performance Vested Options vest in 20% increments on each of the first five anniversaries of December 31, 2007, subject to our achievement of the annual management EBITDA target for the given fiscal year (or certain cumulative performance targets) as detailed in the stock option agreements.

In deciding whether to vest the Original Performance Vested Options, the O&C Committee considers EFH Corp.’s quantitative performance against certain management EBITDA targets. The method of calculating management EBITDA for purposes of vesting the Original Performance Vested Options is the same as the method for calculating management EBITDA for purposes of the EAIP, as described above. The O&C Committee also has broad discretion to consider other qualitative and quantitative criteria that it deems appropriate in connection with its decision to vest the Original Performance Vested Options.

Our management EBITDA for 2009 was less than the management EBITDA target of $5.569 billion set forth in the applicable stock option agreements with respect to 2009. While EFH Corp. did not meet the applicable management EBITDA target, which was originally established in 2007, it exceeded the management EBITDA target established by the O&C Committee in the beginning of 2009 for purposes of the EAIP. In addition, EFH Corp.’s actual SG&A for 2009 was less than the targeted amount of SG&A set by the O&C Committee. Given these achievements, as well as the successful attainment of most of the other annual financial and operational performance targets that were established by the O&C Committee at the beginning of 2009, the O&C Committee exercised its discretionary authority under the 2007 Stock Incentive Plan and approved the vesting of the 2009 Original Performance Vested Options.

In the future, we may make additional discretionary grants of stock options or other equity-based compensation to reward high performance or achievement.

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Equity Investment

In addition to being granted Stock Option Awards, several of our Named Executive Officers (including Messrs. Young, Keglevic, Campbell and Burke) have an equity investment in EFH Corp. These investments have been made through a direct cash investment for shares of EFH Corp. common stock (Mr. Young) and/or through the receipt of restricted stock units (Mr. Young) or deferred shares of EFH Corp. common stock (Messrs. Keglevic, Campbell and Burke) (i) as a result of the executive officer foregoing the right to receive certain payments from EFH Corp., whether in respect of outstanding equity awards issued prior to the Merger or otherwise (Messrs. Campbell and Burke) or (ii) as consideration for compensation forfeited by the executive officer when he left his former employer to join EFH Corp. (Messrs. Young and Keglevic). We believe such investment strongly aligns the interests of our Named Executive Officers with the interests of our shareholders and provides increased incentive to our executive officers to maximize financial and operational performance because the value of their investment is dependant upon the success of EFH Corp. In addition, as we are a private company, the illiquid nature of the investment provides additional retentive value.

Other Elements of Compensation

General

Our executive officers generally have the opportunity to participate in certain of our broad-based employee compensation plans, including our Thrift (401(k)) Plan, retirement plans and non-qualified benefit plans. Please refer to the footnotes to the Summary Compensation table for a more detailed description of our Thrift Plan, the narrative that follows the Pension Benefits table for a more detailed description of our Retirement Plan and Supplemental Executive Retirement Plan and the footnotes to the Nonqualified Deferred Compensation table for a more detailed description of our Salary Deferral Program.

Perquisites

We do not believe that a significant amount of perquisites fit within our compensation philosophy. Those perquisites that exist are intended to serve as part of a competitive total compensation program and to enhance our executive officers’ ability to conduct company business. These benefits include financial planning, a preventive physical health exam and reimbursement for certain spousal travel expenses. Expenditures for the perquisites outlined above are disclosed by individual in footnotes to the Summary Compensation Table.

The following is a summary of perquisites offered to our Named Executive Officers that are not available to all employees:

Executive Financial Planning: We pay for our executive officers to receive financial planning services. This service is intended to support them in managing their financial affairs, which we consider especially important given the high level of time commitment and performance expectation required of our executive officers. Furthermore, we believe that such service helps ensure greater accuracy and compliance with individual tax regulations by our executive officers.

Annual Executive Physical Health Exam: We pay for our executive officers to receive annual physical health exams. The health of our executive officers is important given the vital leadership role they play in directing and operating the company. Our executive officers are important assets of EFH Corp., and this benefit is designed to help ensure their health and long-term ability to serve our shareholders.

Spouse Travel Expenses: From time to time, we pay for an executive officer’s spouse to travel with the executive officer when taking a business trip.

Contingent Payments

We have entered into employment agreements with Messrs. Young, Keglevic, Campbell, Walters 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. 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 of employment. For a description of the applicable provisions in the employment agreements of our Named Executive Officers see “Potential Payments upon Termination or Change in Control.”

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Other

In February 2010, the O&C Committee approved certain other compensation arrangements for Mr. Young and Mr. Burke. For a discussion of these arrangements, please see Item 9B, entitled Other Information in EFH Corp.’s 2009 Form 10-K.

Accounting and Tax Considerations

Accounting Considerations

Under FASB ASC Topic 718, the total amount of compensation expense to be recorded for stock-based awards (e.g., Stock Option Awards granted under the 2007 Stock Incentive Plan) is based on the fair value of the award on the grant date. This fair value is then recorded as expense over the vesting period, with an offsetting increase in paid-in capital. The amount of compensation expense is not subsequently adjusted for changes in our share price, for the actual number of shares distributed, or for any other factors except for true-ups related to estimated forfeitures compared to actual forfeitures. The surrendered shares are considered modifications to the original awards and are treated as an exchange of the original award for a new award. The compensation expense related to the new award represents the incremental costs of the surrendered shares and is based on the new grant date fair value and is recognized over its new vesting period.

Income Tax Considerations

Section 162(m) of the Code limits the tax deductibility by a publicly held company of compensation in excess of $1 million paid to the CEO or any other of its three most highly compensated executive officers other than the principal financial officer. Because EFH Corp. is a privately-held company, Section 162(m) will not limit the tax deductibility of any executive compensation for 2009.

The O&C Committee administers our compensation programs with the good faith intention of complying with Section 409A of the Code.

Organization and Compensation Committee Report

The O&C Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth in this prospectus. Based on this review and discussions, the committee recommended to the Board that the Compensation Discussion and Analysis be included in this prospectus.

Organization and Compensation Committee

Donald L. Evans, Chair

Arcilia C. Acosta

Marc S. Lipschultz

Kenneth Pontarelli

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Summary Compensation Table

The following table provides information for the fiscal years ended December 31, 2009, 2008 and 2007 regarding the aggregate compensation paid to our Named Executive Officers.

Name and Principal Position	Year		Salary ($)		Bonus ($)		Stock Awards ($)		Option Awards ($) (7)		Non- Equity Incentive Plan Compen- sation ($) (8)		Change in Pension Value and Non- qualified Deferred Compen- sation Earnings ($) (9)		All Other Compen- sation ($) (10)		Total ($)
John F. Young (1)		2009		1,000,000		—		—		—		1,469,000		—		105,291		2,574,291
President & CEO of EFH Corp.		2008		912,500		—		3,000,000		13,635,000		1,418,000		—		462,258		19,427,758
		2007		N/A		N/A		N/A		N/A		N/A		N/A		N/A		N/A
Paul M. Keglevic (2)		2009		600,000		150,000		—		1,325,000		664,200		—		73,320		2,812,520
EVP & Chief Financial Officer of EFH Corp.		2008		293,182		250,000		1,125,000		6,442,500		613,800		—		88,508		8,812,990
		2007		N/A		N/A		N/A		N/A		N/A		N/A		N/A		N/A
David A. Campbell (3)		2009		600,000		—		—		2,120,000		642,600		68,861		15,020		3,446,481
President & CEO of Luminant		2008		545,500		5,092,250		2,500,000		7,272,000		625,950		22,779		3,395,878		19,454,357
		2007		382,000		—		2,292,000		—		300,481		14,667		2,342,814		5,331,962
Robert C. Walters (4)		2009		575,000		—		—		1,060,000		610,000		—		81,562		2,326,562
EVP & General Counsel of EFH Corp.		2008		435,609		100,000		—		3,636,000		695,175		—		44,249		4,911,033
		2007		N/A		N/A		N/A		N/A		N/A		N/A		N/A		N/A
James A. Burke (5)		2009		600,000		—		—		933,100		856,800		55,931		23,885		2,469,716
President & CEO of TXU Energy		2008		600,000		—		—		4,454,100		473,918		25,501		639,136		6,192,655
		2007		342,712		—		830,850		—		274,050		9,864		978,189		2,435,665
Rizwan Chand (6)		2009		348,750		—		—		—		—		36,218		2,110,925		2,495,893
Former EVP — Human Resources of EFH Corp		2008		N/A		N/A		N/A		N/A		N/A		N/A		N/A		N/A
		2007		N/A		N/A		N/A		N/A		N/A		N/A		N/A		N/A

(1) Mr. Young commenced employment with EFH Corp. in January 2008. The amounts for 2009 reported as “All Other Compensation” for Mr. Young represent (i) the costs of providing certain perquisites, including $9,728 for financial planning and $863 of taxable reimbursements partially related to his spouse’s travel and (ii) $14,700 and $80,000 for our matching contributions to the EFH Thrift Plan and the Salary Deferral Plan, respectively.

(2) Mr. Keglevic commenced employment with EFH Corp. in July 2008. Mr. Keglevic’s employment agreement provides that we pay him a signing bonus equal to $550,000 as follows: (i) $250,000 payable in July 2008; (ii) $150,000 payable in July 2009 and (iii) $50,000 payable in July 2010, 2011 and 2012. The amount for 2009 reported as “Bonus” for Mr. Keglevic represents the 2009 portion of his signing bonus. The amounts for 2009 reported as “All Other Compensation” for Mr. Keglevic represent (i) the costs of providing certain perquisites, including $2,724 for an executive physical, $3,410 of taxable reimbursements primarily related to his spouse’s travel and $11,836 for moving expenses and (ii) $7,350 and $48,000 for our matching contributions to the EFH Thrift Plan and the Salary Deferral Plan, respectively.

(3) The amount reported as “All Other Compensation” in 2009 for Mr. Campbell represents (i) $10,120 for financial planning and (ii) $4,900 for our matching contributions to the EFH Thrift Plan. The amount reported as “All Other Compensation” in 2008 for Mr. Campbell includes $3,319,963 for a tax gross-up payment that was made in 2009. The tax gross-up payment, which was not reported in the 2008 Summary Compensation Table, related to excise taxes due with respect to a January 2009 payment of $5,092,250 that was provided to Mr. Campbell as an inducement for entering into his employment agreement in 2008. The $5,092,250 was reported in the 2008 Summary Compensation Table under “Bonus,” and we believe the tax gross-up payment should be reported for the same calendar year as the related payment.

(4) Mr. Walters commenced employment with EFH Corp. in March 2008. The amounts for 2009 reported as “All Other Compensation” for Mr. Walters represent (i) the costs of providing certain perquisites, including $16,800 for financial planning, $2,350 for an executive physical and $1,712 of taxable reimbursements primarily related to his spouse’s travel and (ii) $14,700 and $46,000 for our matching contributions to the EFH Thrift Plan and the Salary Deferral Plan, respectively.

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(5) The amounts for 2009 reported as “All Other Compensation” for Mr. Burke represent (i) the costs of providing certain perquisites, including $8,875 for financial planning, $2,350 for an executive physical and $660 of taxable reimbursements and (ii) $12,000 for our matching contributions to the EFH Thrift Plan.

(6) Mr. Chand’s employment with EFH Corp. terminated in October 2009. The amounts for 2009 reported as “All Other Compensation” for Mr. Chand represent (i) the costs of providing certain perquisites, including $8,875 for financial planning and $2,350 for an executive physical (ii) $14,700 for our matching contributions to the EFH Thrift Plan, (iii) $1,485,000 in cash severance due to him under the terms of his employment agreement, and (iv) $600,000 related to his deferred share agreement with EFH Corp.

(7) The amounts reported as “Option Awards” represent the grant date fair value of Stock Option Awards granted in the fiscal year computed for the stock options awarded under the 2007 Stock Incentive Plan in accordance with FASB ASC Topic 718 and do not take into account estimated forfeitures. See table titled “Grants of Plan-Based Awards — 2009.” In February 2010, Mr. Young received certain new Stock Option Awards. The grant date fair value of those Stock Option Awards was $3,405,000.

(8) The amounts in 2009 reported as “Non-Equity Incentive Plan Compensation” were earned by the executive officers in 2009 under the EAIP and are expected to be paid in March 2010.

(9) The amounts in 2009 reported under “Change in Pension Value and Nonqualified Deferred Compensation Earnings” (i) include the aggregate increase in actuarial value of EFH Corp.’s Retirement Plan and Supplemental Retirement Plan and (ii) exclude amounts attributable to the portion of the vested amounts for Messrs. Young ($33,313), Keglevic ($44,409), Walters ($62,351) and Burke ($19,500) that were transferred from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan as of December 31, 2009. For a more detailed description of EFH Corp.’s retirement plans, including the transfers of certain assets and liabilities from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan, please refer to the narrative that follows the table titled “Pension Benefits.” There are no above market earnings for nonqualified deferred compensation that is deferred under the Salary Deferral Program.

(10) As described above, “All Other Compensation” includes amounts associated with our matching contributions to the EFH Thrift Plan and Salary Deferral Plan. Our Thrift Plan allows participating employees to 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 100% of each Named Executive Officer’s contribution up to 6% of the named Executive Officer’s salary. All matching contributions are invested in Thrift Plan investments as directed by the participant. Please refer to the narrative that follows the Nonqualified Deferred Compensation table for a more detailed description of the Salary Deferral Program.

Grants of Plan-Based Awards — 2009

The following table sets forth information regarding grants of compensatory awards to our Named Executive Officers during the fiscal year ended December 31, 2009.

Name	Grant Date		Date of Board Action		Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)						Estimated Future Payouts Under Equity Incentive Plan Awards			All Other Stock Awards: # Shares or Units	All Other Option Awards: # of Securities Underlying Options (#) (2)		Exercise or Base Price of Option Awards ($/sh)		Grant Date Fair Value of Stock and Option Awards (3)
					Threshold ($)		Target ($)		Max. ($)		Threshold (#)	Target (#)	Max. (#)
John F. Young		2/18/09		2/18/09		500,000		1,000,000		2,000,000
Paul M. Keglevic		2/18/09		2/18/09		225,000		450,000		900,000						1,000,000	$	3.50
		12/17/09		10/29/09																1,325,000
David A. Campbell		2/18/09		2/18/09		225,000		450,000		900,000						1,600,000
		12/17/09		10/29/09													$	3.50		2,120,000
Robert C. Walters		2/18/09		2/18/09		215,625		431,250		862,500						800,000
		12/17/09		10/29/09													$	3.50		1,060,000
James A. Burke		2/18/09		2/18/09		225,000		450,000		900,000						690,000
		12/17/09		10/29/09													$	3.50		933,100
Rizwan Chand		—		—		—		—		—						—		—		—

(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 EAIP for each executive officer and each executive officer’s employment agreement. The actual awards for the 2009 plan year are expected to be paid in March 2010 and are reported in the Summary Compensation Table under the heading “Non-Equity Incentive Plan Compensation” and described above under the section entitled “Annual Performance Bonus — EAIP.”

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(2) Represents grants of New Time Vested Options and New Cliff Vested Options under the 2007 Stock Incentive Plan, as described above under “Long-Term Incentive Awards.”

(3) The amounts reported under “Grant Date Fair Value of Stock Award” represent the grant date fair value of stock options related to the 2009 Awards in accordance with FASB ASC Topic 718.

For a discussion of the terms of the New Stock Option Awards granted to each Named Executive Officer (other than Mr. Chand) in connection with such Named Executive Officer surrendering a portion of his Original Performance Vested Options, please see “Long-Term Incentive Awards — Long-Term Equity Incentives.” For a discussion of certain material terms of the employment agreements with the Named Executive Officers, please see “Assessment of Compensation Elements” and “Potential Payments upon Termination or Change in Control.”

Outstanding Equity Awards at Fiscal Year-End — 2009

	Option Awards											Stock Awards
	# of Securities Underlying Unexercised Options					Equity Incentive Plan Awards: # of Securities Underlying Unexercised Unearned Options (4)		Option Exercise Price		Option Expiration Date		# of Shares or Units of Stock That Have Not Vested (5)		Market Value of Shares or Units of Stock That Have Not Vested		Equity Incentive Plan Awards: # of Unearned Shares, Units or Other Rights That Have Not Vested	Equity Incentive Plan Awards: Market Payout Value of Unearned Shares, Units or Rights That Have Not Vested
Name	Exer- cisable		Unexercisable
John F. Young (6)		2,250,000		2,250,000	(1)		3,000,000		5.00		02/01/2018
Paul M. Keglevic		750,000		750,000 500,000 500,000	(1)  (2)  (3)		500,000		5.00 3.50 3.50		12/22/2018 12/17/2019 12/17/2019
													225,000		787,500
David A. Campbell		1,200,000		1,200,000 800,000 800,000	(1)  (2)  (3)		800,000		5.00 3.50 3.50		05/20/2018 12/17/2019 12/17/2019
Robert C. Walters		600,000		600,000 400,000 400,000	(1)  (2)  (3)		400,000		5.00 3.50 3.50		05/20/2018 12/17/2019 12/17/2019
James A. Burke		735,000		735,000 200,000 490,000	(1)  (2)  (3)		490,000		5.00 3.50 3.50		05/20/2018 12/17/2019 12/17/2019
Rizwan Chand		350,000							5.00		04/04/2010

(1) These Original Time Vested Options are scheduled to become exercisable ratably in September 2010, 2011 and 2012 provided the Named Executive Officer has remained continuously employed by EFH Corp. through the applicable vesting date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”).

(2) These New Time Vested Options are scheduled to become exercisable ratably in September 2010, 2011, 2012, 2013 and 2014 provided the Named Executive Officer has remained continuously employed by EFH Corp. through the applicable vesting date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”).

(3) These New Cliff Vested Options are scheduled to become exercisable in September 2014 provided the Named Executive Officer has remained continuously employed by EFH Corp. through that date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”).

(4) If we achieve certain performance targets, these Original Performance Vested Options are eligible to become exercisable as of the end of fiscal years 2010, 2011 and 2012. See “Long-Term Incentive Awards-Long-Term Equity Incentives” for a detailed description of the vesting schedule for the Original Performance Vested Options and the decision by the O&C Committee in February 2010 to approve the vesting of a portion of the Original Performance Vested Options.

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(5) This column reflects deferred shares described above under “Long-Term Incentive Awards-Equity Investment.” The deferred shares for Mr. Keglevic will vest and become nonforfeitable as to (i) 112,500 of the shares on the third anniversary of his employment (July 2011) and (ii) 112,500 of the shares on the fifth anniversary of his employment (July 2013).

(6) In February 2010, Mr. Young surrendered 1,500,000 Original Performance Vested Options listed in the “Equity Incentive Plan Awards: # of Securities Underlying Unexercised Unearned Options” column, and in connection therewith received 1,500,000 New Time Vested options and 1,500,000 New Cliff Vested Options.

Options Exercised and Stock Vested — 2009

None of the Named Executive Officers exercised any of his vested Stock Option Awards in 2009. In addition, none of the Named Executive Officers owned any restricted or deferred shares of EFH Corp. common stock that vested in 2009.

Pension Benefits — 2009

The table set forth below illustrates present value on December 31, 2009 of each Named Executive Officer’s Retirement Plan benefit and benefits payable under the Supplemental Retirement Plan, based on their years of service and remuneration through December 31, 2009:

Name	Plan Name	Number of Years Credited Service (#)		PV of Accumulated Benefit ($)		Payments During Last Fiscal Year ($)
John F. Young	Retirement Plan		N/A		33,313		—
	Supplemental Retirement Plan		N/A		N/A		N/A
Paul M. Keglevic	Retirement Plan		N/A		44,409		—
	Supplemental Retirement Plan		N/A		N/A		N/A
David A. Campbell (1)	Retirement Plan		4.5833		109,838		—
	Supplemental Retirement Plan		7.5000		34,912		—
Robert C. Walters	Retirement Plan		N/A		62,351		—
	Supplemental Retirement Plan		N/A		N/A		N/A
James A. Burke	Retirement Plan		4.1667		99,396		—
	Supplemental Retirement Plan		4.1667		29,397		—
Rizwan Chand	Retirement Plan		3.3333		34,180		—
	Supplemental Retirement Plan		3.3333		41,752		—

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. Accordingly, none of the Named Executive Officers participates in the traditional defined benefit component. Employees hired after January 1, 2002 and before October 1, 2007 are eligible to participate in the cash balance component. In addition, effective December 31, 2009, certain assets and liabilities under the Salary Deferral Program and the Supplemental Retirement Plan were transferred to the cash balance component of the Retirement Plan. Accordingly, Messrs. Campbell and Burke have participated and may continue to participate in the cash balance component of the Retirement Plan; and Messrs. Young, Keglevic and Walters participate in the cash balance component of the Retirement Plan solely with respect to amounts that were transferred from the Salary Deferral Program.

Under the cash balance component of the Retirement Plan, hypothetical accounts are established for participants and credited with monthly contribution credits equal to a percentage of the participant’s compensation (3.5%, 4.5%, 5.5% or 6.5% depending on the participant’s combined age and years of accredited service), contribution credits equal to the amounts transferred from the Salary Deferral Program and/or the Supplemental Retirement Plan effective as of December 31, 2009 and interest credits on all of such amounts based on the average yield of the 30-year Treasury bond for the 12 months ending November 30 of the prior year.

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The Supplemental Retirement Plan provides for the payment of retirement benefits, which would otherwise be limited by the Code or the definition of earnings under the Retirement Plan. Under the Supplemental Retirement Plan, retirement benefits under the cash balance component are calculated in accordance with the same formula used under the Retirement Plan. Participation in EFH Corp.’s Supplemental Retirement Plan has been limited to employees of all of its businesses other than Oncor, who were employed by EFH Corp. (or its participating subsidiaries) on or before October 1, 2007. Accordingly, Messrs. Campbell and Burke participate in the Supplemental Retirement Plan, and Messrs. Young, Keglevic and Walters are not eligible to participate in the Supplemental Retirement Plan.

Benefits accrued under the Supplemental Retirement Plan after December 31, 2004, are subject to Section 409A of the Code. Accordingly, certain provisions of the Supplemental Retirement Plan have been modified in order to comply with the requirements of Section 409A and related guidance.

The present value of the accumulated benefit for the Retirement Plan (the cash balance component) was calculated as the value of their cash balance account projected to age 65 at an assumed growth rate of 4.75% and then discounted back to December 31, 2009 at 5.90%. No mortality or turnover assumptions were applied.

Nonqualified Deferred Compensation — 2009 (1)

The following table sets forth information regarding plans that provide for the deferral of the Named Executive Officers’ compensation on a basis that is not tax-qualified for the fiscal year ended December 31, 2009:

Name	Executive Contributions in Last FY ($)		Registrant Contributions in Last FY ($) (2)		Aggregate Earnings in Last FY ($)		Aggregate Withdrawals/ Distributions ($) (3)			Aggregate Balance at Last FYE ($) (4)
John F. Young		80,000		80,000		56,561		—			281,715
Paul M. Keglevic		48,000		48,000		72		—			87,703
David A. Campbell		—		—		48,558		—			195,891
Robert C. Walters		46,000		46,000		32,367		—			103,402
James A. Burke		—		—		86,658		—			233,262
Rizwan Chand		—		—		28,960		(116,068	)		—

(1) The amounts reported in the Nonqualified Deferred Compensation table include deferrals and the company match under the Salary Deferral Program. The amounts reported as “Executive Contributions in Last FY” are salary deferrals and are also included as “Salary” in the Summary Compensation Table. Under EFH Corp.’s Salary Deferral Program each employee of EFH Corp. and its participating subsidiaries who is in a designated job level and whose annual salary is equal to or greater than an amount established under the Salary Deferral Program ($110,840 for the program year beginning January 1, 2009) may elect to defer up to 50% of annual base salary, and/or up to 100% of any bonus or incentive award, for a maturity period of seven years, for a maturity period ending with the retirement of such employee, or for a combination thereof. EFH Corp. makes a matching award, which vests at the end of the applicable maturity period (subject to acceleration or forfeiture under certain circumstances), equal to 100% of up to the first 8% of salary deferred under the Salary Deferral Program. Deferrals are credited with earnings or losses based on the performance of investment alternatives under the Salary Deferral Program selected by each participant. At the end of the applicable maturity period, the trustee for the Salary Deferral Program distributes the deferred compensation, any vested matching awards and the applicable earnings in cash as a lump sum or in annual installments at the participant’s election made at the time of deferral. EFH Corp. is financing the retirement option portion of the Salary Deferral Program through the purchase of corporate-owned life insurance on the lives of participants. The proceeds from such insurance are expected to allow EFH Corp. to fully recover the cost of the retirement option. Beginning in 2010, certain executive officers, including the Named Executive Officers, will not be eligible to participate in the Salary Deferral Program.

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(2) The amount included in “Registrant Contributions in Last FY” is attributable to EFH Corp.’s matching award under the Salary Deferral Program.

(3) The “Aggregate Withdrawals/Distributions($)” column excludes amounts transferred from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan as of December 31, 2009 for Messrs. Young ($37,500), Keglevic ($48,511), Walters ($71,283) and Burke ($25,000). In accordance with the terms of the Salary Deferral Plan, Mr. Chand forfeited $39,606 of company matching and received a distribution of the remaining balance of his account upon termination of his employment.

(4) A portion of the amounts reported as “Aggregate Balance at Last FYE” are also included in the Summary Compensation Table as follows: for Mr. Young, $80,000 and $66,667 of executive contributions are included as “Salary” for 2009 and 2008, respectively, and $80,000 and $66,667 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively; for Mr. Keglevic, $48,000 and $20,000 of executive contributions are included as “Salary” for 2009 and 2008, respectively, and $48,000 and $20,000 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively; for Mr. Walters, $46,000 and $30,667 of executive contributions are included as “Salary” for 2009 and 2008, respectively, and $46,000 and $30,667 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively; for Mr. Burke, $48,000 and $27,417 of executive contributions are included as “Salary” for 2008 and 2007, respectively, and $48,000 and $27,417 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively. The amounts reported as “Aggregate Balance at Last FYE” reflect decreases resulting from the amounts transferred from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan as of December 31, 2009 for Messrs. Young ($37,500), Keglevic ($48,511), Walters ($71,283) and Burke ($25,000).

Potential Payments upon Termination or Change in Control

The tables and narrative below provide information for payments to each of the Named Executive Officers (or, as applicable, enhancements to payments or benefits) in the event of his termination, including if such termination is voluntary, for cause, as a result of death, as a result of disability, without cause or for good reason or without cause or for good reason in connection with a change in control.

The information in the tables below is presented in accordance with SEC rules, assuming termination of employment as of December 31, 2009.

Employment Arrangements with Contingent Payments

As of December 31, 2009, each of Messrs. Young, Keglevic, Campbell, Walters and Burke had employment agreements with change in control and severance provisions as described in the following tables. In addition, in October 2009, the O&C Committee approved several changes to the compensation arrangements for all of the Named Executive Officers other than Messrs. Young and Chand, which changes were effective as of December 31, 2009 but not yet documented in such Named Executive Officers’ employment agreements. Certain of these changes affected the potential payments of Messrs. Keglevic, Campbell, Walters and Burke and are reflected in the following tables. In February, 2010, Mr. Young’s employment agreement was amended and restated effective retroactively on January 1, 2010. Because the changes to Mr. Young’s employment agreement were not effective as of December 31, 2009, they are not reflected in the following table for Mr. Young, but are described elsewhere in this prospectus. Mr. Chand had an employment agreement, and the change in control and severance terms included in the employment agreement governed until his employment with EFH Corp. terminated in October 2009.

With respect to each Named Executive Officer’s employment agreement, a change in control is generally defined as (i) a transaction that results in a sale of substantially all of our assets to another person and such person having more seats on our Board than the Sponsor Group, (ii) a transaction that results in a person not in the Sponsor Group owning more than 50% of our common stock and such person having more seats on our Board than the Sponsor Group or (iii) a transaction that results in the Sponsor Group owning less than 20% of our common stock and the Sponsor Group not being able to appoint a majority of the directors to our Board.

Each Named Executive Officer’s employment agreement includes customary non-compete and non-solicitation provisions that generally restrict the Named Executive Officer’s ability to compete with us or solicit our customers or employees for his own personal benefit during the term of the employment agreement and 24 months (with respect to Mr. Young) or 18 months (with respect to Messrs. Keglevic, Campbell, Walters and Burke) after the employment agreement expires or is terminated.

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In addition, in October 2009, the O&C Committee approved the adoption of a new LTI to be included by amendment in the employment agreement of Messrs. Keglevic, Campbell, Walters and Burke. Under the terms of the LTI, in the event of the death or disability of any such Named Executive Officer, his termination without cause or resignation for good reason (or in the event we elect not to extend his employment term), or his termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp., in each case prior to September 30, 2012, such named Executive Officer shall be entitled to receive the LTI, or a pro rata portion thereof, calculated as (i) 75% of the aggregate EAIP award actually earned by the Named Executive Officer for any applicable fiscal year completed prior to the date of the Named Executive Officer’s termination, plus (ii) for a termination occurring in fiscal year 2009, 2010, or 2011, 75% of the Named Executive Officer’s prorated annual performance-based cash bonus for the year of termination. In February 2010, Mr. Young’s employment agreement was amended to add a similar new LTI that is calculated based on 100% of the aggregate EAIP award actually earned by Mr. Young for fiscal years 2009, 2010 and 2011.

As of December 31, 2009, each of Messrs. Young, Keglevic, Campbell, Walters and Burke had stock option agreements. Under the stock option agreement for each Named Executive Officer, in the event of such Named Executive Officer’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) following a change in control of EFH Corp., such Named Executive Officer’s Original Time Vested Options would become immediately exercisable as to 100% of the shares of EFH Corp. common stock subject to such options immediately prior to the change in control. As of December 31, 2009, the fair market value of the shares of EFH Corp. common stock underlying each Named Executive Officer’s Original Time Vested Options was less than the exercise price of such options.

1. Mr. Young

Potential Payments to Mr. Young upon Termination as of December 31, 2009 (per employment agreement, restricted stock agreement and stock option agreement, each in effect as of December 31, 2009)

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		N/A		N/A		N/A		N/A	$	5,000,000	$	5,000,000
EAIP		N/A		N/A	$	1,000,000	$	1,000,000		N/A	$	1,000,000
Payment of Common Stock in respect of Restricted Stock Units		N/A	$	1,950,000	$	1,950,000	$	1,950,000	$	1,950,000	$	1,950,000
Acceleration of Stock Option Awards		N/A		N/A		N/A		N/A		N/A	$	0
Deferred Compensation
- Salary Deferral Program		N/A		N/A	$	159,608	$	159,608		N/A	$	159,608
Health & Welfare
- Medical/COBRA		N/A		N/A		N/A		N/A	$	33,273	$	33,273
- Dental/COBRA		N/A		N/A		N/A		N/A	$	2,790	$	2,790
Totals		N/A	$	1,950,000	$	3,109,608	$	3,109,608	$	6,986,063	$	8,145,671

Mr. Young has entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1.    In the event of Mr. Young’s death or disability:

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a. a prorated annual incentive bonus for the year of termination, and

b. payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled.

2.     In the event of Mr. Young’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):

a. a lump sum payment equal to two and one-half times the sum of (i) his annualized base salary and (ii) a prorated annual incentive bonus for the year of termination;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled, and

c. certain continuing health care and company benefits.

3.     In the event of Mr. Young’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two and one-half times the sum of (i) his annualized base salary and (ii) his annual bonus target;

b. a prorated annual incentive bonus for the year of termination;

c. payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled;

d. certain continuing health care and company benefits, and

e. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

In addition, Mr. Young has entered into a restricted stock agreement. Under Mr. Young’s restricted stock agreement, Mr. Young was granted 600,000 restricted stock units, payable in January 2010, with one share of common stock of EFH Corp. for each such unit, all of which were fully vested and nonforfeitable upon grant; provided, however, in the event of Mr. Young’s voluntary termination prior to January 2010, Mr. Young would have had to forfeit all of his restricted stock units.

2. Mr. Keglevic

Potential Payments to Mr. Keglevic upon Termination as of December 31, 2009 (per employment agreement, deferred share agreement and stock option agreement, each in effect as of December 31, 2009, and revisions to such employment agreement that were adopted by the O&C Committee in October 2009 and effective as of December 31, 2009)

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		N/A		N/A		N/A		N/A	$	2,100,000	$	2,100,000
EAIP		N/A		N/A	$	450,000	$	450,000		N/A		N/A
Put Right in respect of Deferred Shares		N/A		N/A	$	3,200,000	$	3,200,000	$	3,200,000	$	3,200,000
Acceleration of Stock Option Awards		N/A		N/A		N/A		N/A		N/A	$	0
LTI Cash Retention Award		N/A		N/A	$	498,150	$	498,150	$	498,150	$	498,150
Deferred Compensation
- Salary Deferral Program		N/A		N/A	$	68,107	$	68,107		N/A	$	68,107
Health & Welfare
- Dental/COBR		N/A		N/A		N/A		N/A	$	2,790	$	2,790
Totals		N/A		N/A	$	4,216,257	$	4,216,257	$	5,800,940	$	5,869,047

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Mr. Keglevic entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1.     In the event of Mr. Keglevic’s death or disability:

a. a prorated annual incentive bonus for the year of termination, and

b. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled.

2.     In the event of Mr. Keglevic’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):

a. for a termination occurring on or prior to the second anniversary of the effective date of the agreement, a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target, and for a termination occurring after the second anniversary of the effective date of the agreement, a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the matching contributions which would have been made on his behalf to EFH Corp.’s Salary Deferral Program had Mr. Keglevic continued his participation in the plan for an additional twelve months;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled, and

c. certain continuing health care and company benefits.

3.     In the event of Mr. Keglevic’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled;

c. certain continuing health care and company benefits, and

d. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

In addition, Mr. Keglevic has entered into a deferred share agreement. Under Mr. Keglevic’s deferred share agreement, EFH Corp. agreed to deliver to Mr. Keglevic 112,500 shares of EFH Corp. common stock on July 1, 2011 and 112,500 shares of EFH Corp. common stock on July 1, 2013; provided, however, that any shares not yet vested shall become 100% vested and become nonforfeitable in the event of Mr. Keglevic’s death or disability or as a result of his termination without cause or for good reason or without cause or for good reason in connection with a change in control. Further, in the event of Mr. Keglevic’s termination prior to July 1, 2013 as a result of death, as a result of disability, without cause or for good reason or without cause or for good reason in connection with a change in control, Mr. Keglevic shall have the right (but not the obligation) to sell to EFH Corp. all (but not less than all) of the shares of EFH Corp. common stock delivered pursuant to the deferred share agreement for a purchase price of $3,200,000.

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3. Mr. Campbell

Potential Payments to Mr. Campbell upon Termination as of December 31, 2009 (per employment agreement, deferred share agreement and stock option agreement, each in effect as of December 31, 2009, and revisions to such employment agreement that were adopted by the O&C Committee in October 2009 and effective as of December 31, 2009)

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		N/A		N/A		N/A		N/A	$	2,100,000	$	2,100,000
EAIP		N/A		N/A	$	450,000	$	450,000		N/A		N/A
Payment of EFH Corp. Common Stock in respect of Vested Deferred Shares	$	1,625,000	$	1,625,000	$	1,625,000	$	1,625,000	$	1,625,000	$	1,625,000
Acceleration of Stock Option Awards		N/A		N/A		N/A		N/A		N/A	$	0
LTI Cash Retention Award		N/A		N/A	$	481,950	$	481,950	$	481,950	$	481,950
Retirement Benefits
- Supplemental Retirement Plan	$	43,511	$	43,511	$	45,205	$	271,531	$	43,511	$	43,511
Deferred Compensation
- Salary Deferral Program (1)	$	77,146	$	77,146	$	77,146	$	77,146	$	77,146	$	77,146
Health & Welfare
- Medical/COBRA		N/A		N/A		N/A		N/A	$	26,719	$	26,719
- Dental/COBRA		N/A		N/A		N/A		N/A	$	2,232	$	2,232
Totals	$	1,745,657	$	1,745,657	$	2,679,301	$	2,905,627	$	4,356,558	$	4,356,558

(1) Mr. Campbell is fully vested in the company matching portion of the Salary Deferral Plan.

Mr. Campbell entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1.     In the event of Mr. Campbell’s death or disability:

a. a prorated annual incentive bonus for the year of termination, and

b. payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled.

2.     In the event of Mr. Campbell’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):

a. for a termination occurring on or prior to the second anniversary of the effective date of the agreement, a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target, and for a termination occurring after the second anniversary of the effective date of the agreement, a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the matching contributions which would have been made on his behalf to EFH Corp.’s Salary Deferral Program had Mr. Campbell continued his participation in the plan for an additional twelve months;

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b. payment of employee benefits, including stock compensations, if any, to which Mr. Campbell may be entitled, and

c. certain continuing health care and company benefits.

3.    In the event of Mr. Campbell’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled;

c. certain continuing health care and company benefits, and

d. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

In addition, Mr. Campbell has entered into a deferred share agreement. Under Mr. Campbell’s deferred share agreement, EFH Corp. agreed to deliver to Mr. Campbell 500,000 shares of EFH Corp. common stock in the event of Mr. Campbell’s termination for any reason.

4. Mr. Walters

Potential Payments to Mr. Walters upon Termination as of December 31, 2009 (per employment agreement and stock option agreement, each in effect as of December 31, 2009, and revisions to such employment agreement that were adopted by the O&C Committee in October 2009 and effective as of December 31, 2009)

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		N/A		N/A		N/A		N/A	$	2,012,500	$	2,012,500
EAIP		N/A		N/A	$	431,250	$	431,250		N/A		N/A
Acceleration of Stock Option Awards		N/A		N/A		N/A		N/A		N/A	$	0
LTI Cash Retention Award		N/A		N/A	$	457,500	$	457,500	$	457,500	$	457,500
Lump Sum Payment		N/A		N/A	$	2,000,000	$	2,000,000	$	2,000,000	$	2,000,000
Deferred Compensation
- Salary Deferral Program		N/A		N/A	$	87,343	$	87,343		N/A	$	87,343
Health & Welfare
- Medical/COBRA		N/A		N/A		N/A		N/A	$	26,618	$	26,618
- Dental/COBRA		N/A		N/A		N/A		N/A	$	2,232	$	2,232
Totals		N/A		N/A	$	2,976,093	$	2,976,093	$	4,498,850	$	4,586,193

Mr. Walters entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1.    In the event of Mr. Walters’ death or disability:

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a. a prorated annual incentive bonus for the year of termination;

b. a lump sum payment equal to $2,000,000, and

c. payment of employee benefits, including stock compensation, if any, to which Mr. Walters may be entitled.

2.    In the event of Mr. Walters’ termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):

a. for a termination occurring on or prior to the second anniversary of the effective date of the agreement, a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target, and for a termination occurring after the second anniversary of the effective date of the agreement, a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the matching contributions which would have been made on his behalf to EFH Corp.’s Salary Deferral Program had Mr. Walters continued his participation in the plan for an additional twelve months;

b. a lump sum payment equal to $2,000,000;

c. payment of employee benefits, including stock compensation, if any, to which Mr. Walters may be entitled, and

d. certain continuing health care and company benefits.

3.    In the event of Mr. Walters’ termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;

b. a lump sum payment equal to $2,000,000;

c. payment of employee benefits, including stock compensation, if any, to which Mr. Walters may be entitled;

d. certain continuing health care and company benefits, and

e. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

5. Mr. Burke

Potential Payments to Mr. Burke upon Termination as of December 31, 2009 (per employment agreement and stock option agreement, each in effect as of December 31, 2009, and revisions to such employment agreement that were adopted by the O&C Committee in October 2009 and effective as of December 31, 2009)

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		N/A		N/A		N/A		N/A	$	1,200,000	$	2,100,000
EAIP		N/A		N/A	$	450,000	$	450,000	$	450,000		N/A
Acceleration of Stock Option Awards		N/A		N/A		N/A		N/A		N/A	$	0
LTI Cash Retention Award		N/A		N/A	$	642,600	$	642,600	$	642,600	$	642,600
Retirement Benefits
- Supplemental Retirement Plan	$	35,747	$	35,747	$	38,099	$	255,572	$	35,747	$	35,747
Deferred Compensation
- Salary Deferral Program	$	66,775	$	66,775	$	128,976	$	128,976	$	66,775	$	128,976
Health & Welfare
- Medical/COBRA		N/A		N/A		N/A		N/A	$	26,618	$	26,618
- Dental/COBRA		N/A		N/A		N/A		N/A	$	2,232	$	2,232
Totals	$	102,522	$	102,522	$	1,259,675	$	1,477,148	$	2,423,972	$	2,936,173

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Mr. Burke entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:

1.    In the event of Mr. Burke’s death or disability:

a. a prorated annual incentive bonus for the year of termination, and

b. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled.

2.    In the event of Mr. Burke’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):

a. a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the matching contributions which would have been made on his behalf to EFH Corp.’s Salary Deferral Program had Mr. Burke continued his participation in the plan for an additional twelve months;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled, and

c. certain continuing health care and company benefits.

3.    In the event of Mr. Burke’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:

a. a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target;

b. payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled;

c. certain continuing health care and company benefits and

d. a tax gross-up payment to offset any excise tax which may result from the change in control payments.

6. Mr. Chand

Mr. Chand’s employment with EFH Corp. terminated in October 2009. Under the terms of his Severance Agreement, EFH Corp. provided Mr. Chand a severance payment which consisted of a lump sum cash payment of (i) $1,485,000, representing the cash severance that was due under his employment agreement and (ii) $600,000 related to his deferred share agreement.

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Excise Tax Gross-Ups

Pursuant to their employment agreements, if any of our Named Executive Officers would be subject to the imposition of the excise tax imposed by Section 4999 of the Code, related to the executive’s employment, but the imposition of such tax could be avoided by approval of our shareholders as described in Section 280G(b)(5)(B) of the Code, then such executive may cause EFH Corp. to seek such approval, in which case EFH Corp. will use its reasonable best efforts to cause such approval to be obtained and such executive will cooperate and execute such waivers as may be necessary so that such approval avoids imposition of any excise tax under Section 4999. If such executive fails to cause EFH Corp. to seek such approval or fails to cooperate and execute the waivers necessary in the approval process, such executive shall not be entitled to any gross-up payment for any resulting tax under Section 4999.

Compensation Committee Interlocks and Insider Participation

There are no relationships among our executive officers, members of the O&C Committee or entities whose executives served on the O&C Committee that required disclosure under applicable SEC rules and regulations. For a description of related person transactions involving members of the O&C Committee, see “Related Person Transactions.”

Director Compensation

The table below sets forth information regarding the aggregate compensation paid to the members of the Board during the year ended December 31, 2009. Directors who are officers of EFH Corp. or members of the Sponsor Group (or their respective affiliates) do not receive any fees for service as a director. EFH Corp. reimburses directors for certain reasonable expenses incurred in connection with their services as directors.

Name	Fees Earned or Paid in Cash ($)		Stock Awards ($)		All Other Compensation ($)		Total ($)
Arcilia C. Acosta (1)		150,000		100,000		—		250,000
David Bonderman		—		—		—		—
Donald L. Evans (2)		2,000,000		425,000		0		2,425,000
Thomas D. Ferguson		—		—		—		—
Frederick M. Goltz		—		—		—		—
James R. Huffines (1)(3)		150,000		100,000		900,000		1,150,000
Scott Lebovitz		—		—		—		—
Jeffrey Liaw		—		—		—		—
Marc S. Lipschultz		—		—		—		—
Michael MacDougall		—		—		—		—
Lyndon L. Olson, Jr. (1)(3)		150,000		100,000		900,000		1,150,000
Kenneth Pontarelli		—		—		—		—
William K. Reilly (1)		150,000		100,000		0		250,000
Jonathan D. Smidt		—		—		—		—
John F. Young		—		—		—		—
Kneeland Youngblood (1)		150,000		100,000		0		250,000

(1) Ms. Acosta and Messrs. Huffines, Olson, Reilly and Youngblood receive $150,000 annually and an annual equity award (paid in shares of EFH Corp. common stock) valued at $100,000 (the grant date fair value) for their service as a director.

(2) In 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; and

2. 200,000 shares of restricted stock, half of which vested during 2009, 50,000 shares at $5.00 per share and 50,000 shares at $3.50 per share. The value of the shares that vested during 2009 is reported in the table above under the heading “Stock Awards.”

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Under the consulting agreement, Mr. Evans also received options to purchase 600,000 shares of EFH Corp.’s common stock at an exercise price of $5.00 per share. As a result, there should have been an “Option Awards” column in last year’s Director Compensation table and it should have included $551,250 as the grant date fair value for the options granted to Mr. Evans in May 2008 based upon rules for valuing stock option awards as they existed last year. The consulting agreement had a term running through October 2009. In February 2010, EFH Corp. entered into a new consulting agreement with Mr. Evans effective retroactively to October 10, 2009, pursuant to which Mr. Evans is entitled to receive an annual fee of $2,000,000. The term of the new consulting agreement expires in October 2012.

(3) In December 2007, EFH Corp. entered into consulting agreements with Messrs. Huffines and Olson. As compensation for their consulting services, they received annual fees of $225,000, in addition to their standard director compensation described above. The amounts earned pursuant to these consulting agreements in 2009 are reflected above in the “All Other Compensation” column. In November 2009, the consulting agreements with Messrs. Huffines and Olson were terminated. In January 2010, Messrs. Huffines and Olson were each paid a $675,000 bonus for their exemplary efforts and past performance while serving as consultants.

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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 December 31, 2009.

	(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		62,289,801	$	4.61		9,710,199
		62,289,801	$	4.61		9,710,199

Note:	Includes 49.8 million stock options with a weighted average exercise price of $4.63.
	Includes 4.0 million vested and unvested restricted shares, deferred shares and stock granted to directors as part of their compensation plan.

Beneficial Ownership of Common Stock of Energy Future Holdings Corp.

The following table lists the number of shares of common stock of EFH Corp. beneficially owned by each director and certain current and former executive officers of EFH Corp. and the holders of more than 5% of EFH Corp.’s common stock as of December 10, 2010.

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Name	Number of Shares Beneficially Owned		Percent of Class
Texas Energy Future Holdings Limited Partnership (1)		1,657,600,000		97.85	%
Arcilia C. Acosta (2)		100,770		*
David Bonderman (3)		1,657,600,000		97.85	%
Donald L. Evans (4)		1,000,000		*
Thomas D. Ferguson (5)		1,657,600,000		97.85	%
Frederick M. Goltz (6)		1,657,600,000		97.85	%
James R. Huffines		390,770		*
Scott Lebovitz (5)		1,657,600,000		97.85	%
Jeffrey Liaw (3)		1,657,600,000		97.85	%
Marc S. Lipschultz (6)		1,657,600,000		97.85	%
Michael MacDougall (3)		1,657,600,000		97.85	%
Lyndon L. Olson, Jr.		250,770		*
Kenneth Pontarelli (5)		1,657,600,000		97.85	%
William K. Reilly		230,770		*
Jonathan D. Smidt (6)		1,657,600,000		97.85	%
John F. Young (7)		5,062,009		*
Kneeland Youngblood		170,770		*
James A. Burke (8)		1,715,000		*
David A. Campbell (9)		2,660,000		*
M. Rizwan Chand (10)		0		*
Paul M. Keglevic (11)		1,575,000		*
Robert C. Walters (12)		1,080,000		*
M. A. McFarland (13)		1,143,550		*
All directors and current executive officers as a group (24 persons)		1,674,219,409		98.83	%

 * Less than 1%.

(1) Texas Holdings beneficially owns 1,657,600,000 shares of EFH Corp. The sole general partner of Texas Holdings is Texas Energy Future Capital Holdings LLC (Texas Capital), which, pursuant to the Amended and Restated Limited Partnership Agreement of Texas Holdings, has the right to vote all of the EFH Corp. shares owned by Texas Holdings. The address of both Texas Holdings and Texas Capital is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.

(2) 70,000 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. (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 (TC LLC Agreement), to have shared voting or dispositive power. The ultimate general partners of the TPG Entities are TPG Advisors IV, Inc. and TPG Advisors V, Inc. David Bonderman and James Coulter are the sole shareholders and directors of TPG Advisors IV Inc. and TPG Advisors V Inc., and therefore, Messrs. Bonderman and Coulter, TPG Advisors IV Inc. and TPG Advisors V Inc. may each be deemed to beneficially own the shares held by the TPG Entities. Messrs. Bonderman, Liaw and MacDougall are managers of Texas Capital. By virtue of their position in relation to Texas Capital and the TPG Entities, Messrs. Bonderman, Liaw and MacDougall may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Liaw and MacDougall disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102.

(4) Includes 600,000 shares issuable upon exercise of vested options.

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(5) Includes the 1,657,600,000 shares owned by Texas Holdings, over which GS Capital Partners VI Fund, L.P., GSCP VI Offshore TXU Holdings, L.P., GSCP VI Germany TXU Holdings, L.P., GS Capital Partners VI Parallel, L.P., GS Global Infrastructure Partners I, L.P., GS Infrastructure Offshore TXU Holdings, L.P. (GSIP International Fund), GS Institutional Infrastructure Partners I, L.P., Goldman Sachs TXU Investors L.P. and Goldman Sachs TXU Investors Offshore Holdings, L.P. (collectively, Goldman Entities) may be deemed, as a result of their ownership of 27.02% of Texas Capital’s outstanding units and certain provision of the TC LLC Agreement, to have shared voting or dispositive power. Affiliates of The Goldman Sachs Group, Inc. (Goldman Sachs) are the general partner, managing general partner or investment manager of each of the Goldman Entities, and each of the Goldman Entities shares voting and investment power with certain of their respective affiliates. Each of Goldman Sachs and the Goldman Entities disclaims beneficial ownership of such shares of common stock except to the extent of its pecuniary interest therein. Messrs. Ferguson, Lebovitz and Pontarelli are managers of Texas Capital and executives with affiliates of Goldman Sachs. By virtue of their position in relation to Texas Capital and the Goldman Entities, Messrs. Ferguson, Lebovitz and Pontarelli may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Ferguson, Lebovitz and Pontarelli disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is c/o Goldman, Sachs & Co., 85 Broad Street, New York, New York 10004.

(6) Includes the 1,657,600,000 shares owned by Texas Holdings, over which KKR 2006 Fund L.P., KKR PEI Investments, L.P., KKR Partners III, L.P., KKR North American Co-Invest Fund I L.P. and TEF TFO Co-Invest, LP (KKR Entities) may be deemed, as a result of their ownership of 37.05% of Texas Capital’s outstanding units and certain provision of the TC 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 57th Street, Suite 4200, New York, New York 10019.

(7) Includes 4,050,000 shares issuable upon exercise of vested options.

(8) 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 1,265,00 shares issuable upon exercise of vested options.

(9) Includes 500,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 2,160,000 shares issuable upon exercise of vested options.

(10) Mr. Chand’s employment with EFH Corp. terminated in October 2009.

(11) Includes 225,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 1,350,000 shares issuable upon exercise of vested options.

(12) Includes 1,080,000 shares issuable upon exercise of vested options.

(13) Includes 1,080,000 shares issuable upon exercise of vested options.

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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 the Executive Committee; or

3. the transaction involves compensation approved by the Organization and Compensation Committee of the Board.

For purposes of this policy, the term “related person” includes EFH Corp.’s directors, executive officers, 5% shareholders and their immediate family members. “Immediate family members” means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law or any person (other than a tenant or employee) sharing the household of a director, executive officer or 5% shareholder.

A “related person transaction” is a transaction between EFH Corp. or its subsidiaries and a related person, other than the types of transactions described below, which are deemed to be pre-approved by the Audit Committee of the Board:

1. any compensation paid to a director if the compensation is required to be reported under Item 402 of Regulation S-K of the Securities Act;

2. any transaction with another company at which a related person’s only relationship is as an employee (other than an executive officer), director or beneficial owner of less than 10% of that company’s ownership interests;

3. any charitable contribution, grant or endowment by EFH Corp. to a charitable organization, foundation or university at which a related person’s only relationship is as an employee (other than an executive officer) or director;

4. transactions where the related person’s interest arises solely from the ownership of EFH Corp.’s equity securities and all holders of that class of equity securities received the same benefit on a pro rata basis;

5. transactions involving a related party where the rates or charges involved are determined by competitive bids;

6. any transaction with a related party involving the rendering of services as a common or contract carrier, or public utility, as rates or charges fixed in conformity with law or governmental authority;

7. any transaction with a related party involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture, or similar service;

8. transactions available to all employees or customers generally (unless required to be disclosed under Item 404 of Regulation S-K of the Securities Act, if applicable);

9. transactions involving less than $100,000 when aggregated with all similar transactions;

10. transactions between EFH Corp. and its subsidiaries or between subsidiaries of EFH Corp.;

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11. transactions not required to be disclosed under Item 404 of Regulation S-K under the Securities Act of 1933; and

12. open market purchases of the EFH Corp. or its subsidiaries’ debt or equity securities and interest payments on such debt.

The Board has determined that it is appropriate for the Audit Committee of the Board to review and approve or ratify related person transactions. Accordingly, at least annually, management reviews related person transactions to be entered into by EFH Corp. or its subsidiaries, if any. After review, the Audit Committee of the Board approves/ratifies or disapproves such transactions. Management updates the Audit Committee of the Board as to any material changes to such related person transactions. In unusual circumstances, EFH Corp. or its subsidiaries may enter into related person transactions in advance of receiving approval, provided that such related person transactions are reviewed and ratified as soon as reasonably practicable by the Audit Committee of the Board. If the Audit Committee of the Board determines not to ratify such transactions, EFH Corp. shall make all reasonable efforts to cancel or otherwise terminate such transactions.

The related person transactions described below under “Related Person Transactions — Business Affiliations,” were ratified by the Audit Committee of the Board pursuant to the policy described above. All other related person transactions were approved prior to the Board’s adoption of this policy, but were approved by either the Board or its Executive Committee. Transactions described under “Related Person Transactions — Transactions with Sponsor Affiliates” are not related person transactions under the EFH Corp. policy because they are not with a director, executive officer, 5% shareholder or any of their immediate family members, but are described in the interest of greater disclosure.

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 (LP Agreement) in respect of EFH Corp.’s parent company, Texas Holdings and (ii) the LLC Agreement in respect of Texas Holdings’ sole general partner, Texas Capital. The LP Agreement provides that Texas Capital has the right to vote or execute consents with respect to any shares of EFH Corp.’s common stock owned by Texas Holdings. The LLC Agreement and LP Agreement contain agreements among the parties with respect to the election of EFH Corp.’s directors, restrictions on the issuance or transfer of interests in EFH Corp., including tag-along rights and drag-along rights, and other corporate governance provisions (including the right to approve various corporate actions).

The LLC Agreement provides that Texas Capital and its members will take all action required to ensure that the managers of Texas Capital are also members of EFH Corp.’s Board. Pursuant to the LLC Agreement each of (i) KKR 2006 Fund L.P. and affiliated investment funds, (ii) TPG Partners V, L.P. and affiliated investment funds and (iii) certain funds affiliated with Goldman Sachs, has the right to designate three managers of Texas Capital. These rights are subject to maintenance of certain investment levels in Texas Holdings.

Registration Rights Agreement

The Sponsor Group and the Co-Investors entered into a registration rights agreement with EFH Corp. upon completion of the Merger. Pursuant to this agreement, in certain circumstances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.’s common stock owned directly or indirectly by them under the Securities Act. In certain circumstances, the Sponsor Group and the Co-Investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.’s common stock under the Securities Act that it may undertake. In 2008 and 2009, Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and Messrs. Young, Greene, Campbell, Walters, Burke, Keglevic, McFarland, Enze, Kaplan and Landy, each of whom are executive officers of EFH Corp., became parties to this agreement.

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Management Services Agreement

In October 2007, in connection with the Merger, the Sponsor Group and Lehman Brothers Inc. entered into a management agreement with EFH Corp. (Management Agreement), pursuant to which affiliates of the Sponsor Group provide management, consulting, financial and other advisory services to EFH Corp. Pursuant to the Management Agreement, affiliates of the Sponsor Group are entitled to receive an aggregate annual management fee of $35 million, which amount increases 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of EFH Corp. or in connection with an initial public offering of EFH Corp. or if the parties thereto mutually agree to terminate the Management Agreement. Pursuant to the Management Agreement, affiliates of the Sponsor Group and Lehman Brothers Inc. were paid transaction fees of $300 million 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 $36 million, inclusive of expenses, to the Sponsor Group during 2009.

Indemnification Agreement

Concurrently with entering into the Management Agreement, the Sponsor Group, Texas Holdings and EFH Corp. entered into an indemnification agreement (Indemnification Agreement), pursuant to which EFH Corp. and Texas Holdings agree to indemnify the Sponsor Group and their affiliates against any claims relating to (i) certain securities and financing transactions relating to the Merger, (ii) the performance of transaction services pursuant to the Management Agreement, (iii) actions or failures to act by EFH Corp., Texas Holdings, Texas Capital or their subsidiaries or affiliates (collectively, Company Group), (iv) service as an officer or director of, or at the request of, any member of the Company Group, and (v) any breach or alleged breach of fiduciary duty as a director or officer of any member of the Company Group.

Sale Participation Agreement

Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and each of our executive officers have entered into sale participation agreements with EFH Corp. Pursuant to the terms of these agreements, among other things, shares of EFH Corp.’s common stock held by these individuals are subject to tag-along and drag-along rights in the event of a sale by the Sponsor Group of shares of EFH Corp.’s common stock held by the Sponsor Group.

Certain Charter Provisions

EFH Corp.’s restated certificate of formation contains provisions limiting directors’ obligations in respect of corporate opportunities.

Management Stockholders’ Agreement

Subject to a management stockholders’ agreement, certain members of management, including EFH Corp.’s directors, executive officers, along with other members of management, elected to invest in EFH Corp. by contributing cash or common stock, or a combination of both, to EFH Corp. prior to or following the Merger and receiving common stock in EFH Corp. in exchange therefore. The net aggregate amount of this investment as of December 31, 2009 is approximately $42.6 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

Certain members of our Board have entered into a stockholders’ agreement with EFH Corp. These stockholders’ agreements create certain rights and restrictions on the equity, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.

Business Affiliations

Mr. Olson, a member of our board, has an ownership interest in 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 2009, Oncor paid TMD approximately $1.2 million and paid Metrum approximately $0.2 million. TMD tests Oncor’s high voltage personal protective equipment. Metrum provides Oncor with cellular-based wireless communications equipment for its meters. Oncor is Metrum’s largest customer. The business relationships with both TMD and Metrum commenced several years prior to Mr. Olson joining the Board.

Transactions with Sponsor Affiliates

TCEH has entered into the TCEH Senior Secured Facilities, and Oncor has entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners. These transactions were approved by the Board of Directors.

Affiliates of the Sponsor Group participated in the debt exchange offers completed in November 2009 by EFH Corp., EFIH and EFIH Finance to exchange new senior secured notes for certain EFH Corp. and TCEH notes (see Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for additional information). Goldman, Sachs & Co. and KKR Capital Markets LLC were paid customary fees in the amounts of $750,000 and $260,000, respectively, as compensation for their services as dealer managers in the debt exchange offers and TPG Capital, L.P. received a fee in the amount of $260,000 as compensation for the advisory services it rendered in connection with the debt exchange offers. Goldman, Sachs & Co. also acted as a dealer manager and solicitation agent in debt exchange offers completed in August 2010 as discussed in Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010, and received fees of $7 million in connection therewith.

Also, Goldman, Sachs & Co. acted as an initial purchaser in EFH Corp.’s issuance of $500 million principal amount of the notes and received fees totaling $3 million (see Note 12 to EFH Corp.’s historical consolidated financial statements for the year ended December 31, 2009 for additional information). Goldman, Sachs & Co. also acted as an initial purchaser in the issuance of $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) in October 2010 as discussed in Note 6 to EFH Corp.’s historical condensed consolidated financial statements for the three and nine months ended September 30, 2010, and received fees totaling $1 million in connection therewith.

Affiliates of GS Capital Partners have from time to time engaged in commercial and investment banking and financial advisory transactions with EFH Corp. in the normal course of business. Affiliates of Goldman Sachs & Co. are party to certain commodity and interest rate hedging transactions with EFH Corp. in the normal course of business.

From time to time affiliates of the Sponsor Group may acquire debt or debt securities issued by EFH Corp. or its subsidiaries in open market transactions or through loan syndications.

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Members of the Sponsor Group and/or their respective affiliates have from time to time entered into, and may continue to enter into, arrangements with us to use our products and services in the ordinary course of their business, which often result in revenues to us in excess of $120,000 annually. In addition, we have entered into, and may continue to enter into, arrangements with members of the Sponsor Group and/or their respective affiliates to use their products and services in the ordinary course of their business, which often result in revenues to members of the Sponsor Group or their respective affiliates in excess of $120,000 annually.

Director Independence

Though not formally considered by the Board because EFH Corp.’s common stock is not currently registered with the SEC or traded on any national securities exchange, based upon the listing standards for issuers of equity securities on the New York Stock Exchange, 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 “Executive Compensation — Director Compensation.” Accordingly, we believe that Ms. Acosta is the only member of the Organization and Compensation Committee who would meet the New York Stock Exchange’s independence requirements for issuers of equity securities. We believe that none of the members of EFH Corp.’s Governance and Public Affairs Committee would meet the New York Stock Exchange’s independence requirements for issuers of equity securities. Under the New York Stock Exchange’s audit committee independence requirement for issuers of debt securities, Messrs. Huffines and Youngblood and Ms. Acosta, who constitute the Audit Committee, are considered independent.

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THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

EFH Corp. and the guarantors of the outstanding notes have entered into a registration rights agreement with the initial purchasers of the outstanding notes and other purchasers of the outstanding notes in which we agreed, under certain circumstances, to use our reasonable best efforts to file a registration statement relating to offers to exchange the outstanding notes for exchange notes and to complete the exchange offer 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 in January 2010 through July 2010.

Under the circumstances set forth below, EFH Corp. and the guarantors will use our reasonable best 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 offer as contemplated by the registration rights agreement;

• if the exchange offer is not consummated within 360 days after the date of issuance of the outstanding notes;

• if any initial purchaser of the outstanding notes so requests with respect to the outstanding notes not eligible to be exchanged for the exchange notes and held by it within 30 days after the consummation of the exchange offer; or

• if any holder that participates in the exchange offer does not receive freely transferable exchange notes in exchange for tendered outstanding notes.

Under the registration rights agreement, if EFH Corp. fails to complete the exchange offer (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 0.50% per annum thereafter, in each case, until the exchange offer is completed or the shelf registration statement, if required, is declared effective by the SEC or the outstanding notes cease to constitute transfer restricted notes.

If you wish to exchange your outstanding notes for exchange notes in the exchange offer, you will be required to make the following written representations:

• you are not our affiliate or an affiliate of any guarantor within the meaning of Rule 405 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; and

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

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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 offer 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 offer. 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 Offer

On the terms and subject to the conditions set forth in this prospectus and in the accompanying letter of transmittal, EFH Corp. will accept for exchange in the exchange offer 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 offer.

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 offer, 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 offer is not conditioned upon any minimum aggregate principal amount of outstanding notes being tendered for exchange.

As of the date of this prospectus, $1,060,757,000 aggregate principal amount of the 10.000% Senior Notes due 2020 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 offer. EFH Corp. intends to conduct the exchange offer 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 offer 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’ 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 the exchange offer and to refuse to accept the occurrence of any of the conditions specified below under “— Conditions to the Exchange Offer.”

If you tender your outstanding notes in the exchange offer, 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 offer. It is important that you read “— Fees and Expenses” below for more details regarding fees and expenses incurred in the exchange offer.

Expiration Date, Extensions and Amendments

As used in this prospectus, the term “expiration date” means 11:59 p.m., New York City time, on March 1, 2011. However, if we, in our sole discretion, extend the period of time for which the exchange offer is open, the term “expiration date” will mean the latest time and date to which we shall have extended the expiration of the exchange offer.

To extend the period of time during which the exchange offer is 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 offer);

• to extend the exchange offer or to terminate the exchange offer if any of the conditions set forth below under “— Conditions to the Exchange Offer” 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 the exchange offer in any manner. In the event of a material change in the exchange offer, 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 the exchange offer 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 Offer

Despite any other term of the exchange offer, 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 the exchange offer as provided in this prospectus prior to the expiration date if in its reasonable judgment:

• the exchange offer 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 offer that, in our judgment, would reasonably be expected to impair our ability to proceed with the exchange offer.

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 Offer,” “— 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 offer is 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 offer.

EFH Corp. expressly reserves the right to amend or terminate the exchange offer and to reject for exchange any outstanding notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offer 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 (the “TIA”).

Procedures for Tendering Outstanding Notes

In order to participate in the exchange offer, you must properly tender your outstanding notes to the exchange agent as described below. It is your responsibility to properly tender your notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender.

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If you have any questions or need help in exchanging your notes, please contact the exchange agent, whose contact information is set forth in “Prospectus Summary — The Exchange Offer — Exchange Agent.”

All of the outstanding notes were issued in book-entry form, and all of the outstanding notes are currently represented by global certificates held for the account of DTC. We have confirmed with DTC that the outstanding notes may be tendered using ATOP instituted by DTC. The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the exchange offer and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their outstanding notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an “agent’s message” to the exchange agent. The agent’s message will state that DTC has received instructions from the participant to tender outstanding notes and that the participant agrees to be bound by the terms of the letter of transmittal.

By using the ATOP procedures to exchange outstanding notes, you will not be required to deliver a letter of transmittal to the exchange agent. However, you will be bound by its terms just as if you had signed it.

There is no procedure for guaranteed late delivery of the notes.

Determinations Under the Exchange Offer

We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered outstanding notes and withdrawal of tendered outstanding notes. Our determination will be final and binding. We reserve the absolute right to reject any outstanding notes not properly tendered or any outstanding notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular outstanding notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of outstanding notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of outstanding notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of outstanding notes will not be deemed made until such defects or irregularities have been cured or waived. Any outstanding notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, promptly following the expiration date.

When We Will Issue Exchange Notes

In all cases, we will issue exchange notes for outstanding notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

• a book-entry confirmation of such outstanding notes into the exchange agent’s account at DTC; and

• a properly transmitted agent’s message.

Return of Outstanding Notes Not Accepted

If we do not accept any tendered outstanding notes for exchange, the unaccepted outstanding notes will be returned without expense to their tendering holder. Such non-accepted outstanding notes will be credited to an account maintained with DTC. This action will occur promptly after the expiration or termination of the exchange offer.

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Your Representations to Us

By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

• any exchange notes that you receive will be acquired in the ordinary course of your business;

• you have no arrangement or understanding with any person or entity to participate in the distribution of the exchange notes;

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

• if you are a broker-dealer that will receive exchange notes for your own account in exchange for outstanding notes, you acquired those notes as a result of market-making activities or other trading activities and you will deliver a prospectus, as required by law, in connection with any resale of such exchange notes; and

• you are not our “affiliate,” as defined in Rule 405 of the Securities Act.

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, you must comply with the appropriate procedures of DTC’s ATOP system.

We will determine all questions as to the validity, form and eligibility of withdrawals, 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 offer. 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 offer. 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.

Exchange Agent

The Bank of New York Mellon Trust Company, N.A. has been appointed as the exchange agent for the exchange offer. The Bank of New York Mellon Trust Company, N.A. 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 and requests for additional copies of this prospectus or of the letter of transmittal 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 Trust Company, N.A. c/o The Bank of New York Mellon Corporate Trust Operations Reorganization Unit 480 Washington Boulevard – 27th Floor Jersey City, NJ 07310 Attn: Mrs. Carolle Montreuil	The Bank of New York Mellon Trust Company, N.A. c/o The Bank of New York Mellon Corporate Trust Operations Reorganization Unit 480 Washington Boulevard – 27th Floor Jersey City, NJ 07310 Attn: Mrs. Carolle Montreuil	The Bank of New York Mellon Trust Company, N.A. c/o The Bank of New York Mellon Corporate Trust Operations Reorganization Unit 480 Washington Boulevard – 27th Floor Jersey City, NJ 07310 Attn: Mrs. Carolle Montreuil

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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 offer. 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 offer 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 offer.

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 offer. We will record the expenses of the exchange offer as incurred.

Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchanges of outstanding notes under the exchange offer. 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 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 offer.

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 request that outstanding notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder will be required to pay any applicable transfer tax.

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Consequences of Failure to Exchange

If you do not exchange your outstanding notes for exchange notes under the exchange offer, 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 prospectus 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 offer 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 offer or otherwise. We have no present plans to acquire any outstanding notes that are not tendered in the exchange offer 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.

As of the date of this prospectus, the Issuer has issued $1,060,757,000 aggregate principal amount of 10.000% Senior Secured Notes due 2020 (the “Notes”). The Notes were issued under an Indenture dated as of January 12, 2010 and supplemental indentures thereto (collectively, the “Indenture”) among the Issuer, the Guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”). The Notes were issued in private transactions that were not subject to the registration requirements of the Securities Act. Except as set forth herein, the terms of the Notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act.

Oncor Electric Delivery Company LLC (“Oncor Electric Delivery”) has undertaken certain ring-fencing measures to separate itself, its subsidiaries and its immediate parent, Oncor Electric Delivery Holdings Company LLC (“Oncor Holdings”), from the Issuer and the Issuer’s other Subsidiaries. Those measures include the Oncor Subsidiaries being treated as “Unrestricted Subsidiaries” with respect to the 10.875% Senior Notes due 2017, 11.250%/12.000% Senior Toggle Notes due 2017 and 9.75% Senior Secured Notes due 2019, in each case issued by the Issuer, and with respect to the 9.75% Senior Secured Notes due 2019 and 10.000% Senior Secured Notes due 2020 (the “EFIH 10.000% Notes”), in each case issued by Energy Future Intermediate Holding Company LLC (“EFIH”) and EFIH Finance Inc. In order to comply with these ring-fencing obligations, the Oncor Subsidiaries will also be Unrestricted Subsidiaries with respect to the Notes. As Unrestricted Subsidiaries, the Oncor Subsidiaries are not subject to any of the covenants described herein and do not guarantee the Notes.

The Holders of the Notes, by accepting the Notes, acknowledge (i) the legal separateness of the Issuer and the Guarantors from the Oncor Subsidiaries, (ii) that the lenders under the Oncor Electric Delivery Facility and the holders of Oncor Electric Delivery’s existing debt instruments have likely advanced funds thereunder in reliance upon the separateness of the Oncor Subsidiaries from the Issuer and the Guarantors, (iii) that the 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 any Oncor Subsidiary, (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 any Oncor Subsidiary, 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 the 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, by accepting the Notes, 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 any Oncor Subsidiary, or against any of the Oncor Subsidiaries’ assets. The Holders further acknowledge and agree that each of the 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 and the Security Documents, does not purport to be complete and is qualified in its entirety by reference to the provisions of the Indenture and the Security Documents, including the definitions therein of certain terms used below. We urge you to read the Indenture and the Security Documents because they, and not this description, define your rights as Holders of the Notes. You may request copies of the Indenture and the Security Documents at our address set forth under the heading “Prospectus Summary.”

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Brief Description of Notes and the Guarantees

The Notes:

• are senior obligations of the Issuer and rank equally in right of payment with all Senior Indebtedness of the Issuer (including the 9.75% Notes and the applicable Existing Notes);

• are effectively subordinated to any Indebtedness of the Issuer secured by assets of the Issuer, to the extent of the value of the assets securing such Indebtedness;

• are structurally subordinated to all Indebtedness and other liabilities of non-guarantor Subsidiaries, including the Oncor Subsidiaries, TCEH and its Subsidiaries, any of the Issuer’s Foreign Subsidiaries and any other Unrestricted Subsidiaries;

• are senior in right of payment to any future Subordinated Indebtedness of the Issuer; and

• are initially unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Energy Future Competitive Holdings Company (“EFCH”) and on a senior secured basis (to the extent of the Collateral) by EFIH, as described below under “— Guarantees.”

The Guarantees:

• are a general senior obligation of each Guarantor;

• in the case of the Guarantee from EFIH, are secured, equally and ratably with EFIH’s guarantee of the 9.75% Notes, the EFIH Notes and the EFIH 10.000% Notes, by the pledge of any investments EFIH owns in any Oncor Subsidiary (as described below under “— Security for the Notes”), which as of the date of this prospectus consists of all of the membership interests it owns in Oncor Holdings;

• in the case of the Guarantee from EFCH, are not secured;

• rank equally in right of payment with all existing and future Senior Indebtedness of each Guarantor;

• in the case of the Guarantee from EFIH, are effectively senior to all unsecured Indebtedness of EFIH to the extent of the value of the Collateral securing such Guarantee;

• are effectively subordinated to all secured Indebtedness of each Guarantor secured by assets other than the Collateral to the extent of the value of the assets securing such Indebtedness;

• are structurally subordinated to any existing and future indebtedness and liabilities of Subsidiaries of a Guarantor that do not Guarantee the Notes, including the Oncor Subsidiaries in the case of EFIH, and TCEH and its Subsidiaries in the case of EFCH, and any other Unrestricted Subsidiaries;

• are senior in right of payment to any future Subordinated Indebtedness of each Guarantor; and

• are effectively senior to all obligations under any future Junior Lien Debt with respect to the Collateral.

See “Risk Factors — Risks Related to the Notes — The liabilities of each of EFH Corp. and EFCH currently exceed its assets as shown on its most recent quarterly balance sheet. If a court were to find that EFH Corp., EFCH or EFIH were insolvent before or after giving effect to the offering of the notes and did not receive reasonably equivalent value or fair consideration for the issuance of the notes or the incurrence of a guarantee or the pledge of the Collateral, as applicable, the court may void all or a portion of the obligations represented by the notes or the guarantee of the notes by EFCH or EFIH or the pledge of the Collateral by EFIH as a fraudulent conveyance.”

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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 or Additional Interest in respect of the Notes, expenses, indemnification or otherwise, on the terms set forth in the Indenture by executing the Indenture.

The Issuer and the Guarantors are holding companies and none of the Issuer’s or the Guarantors’ other Subsidiaries have guaranteed the Notes. In the event of a bankruptcy, liquidation or reorganization of any of the 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 or the Guarantors. None of TCEH, the Subsidiaries of TCEH, or the Oncor Subsidiaries have guaranteed the Notes. For the year ended December 31, 2009 and the nine months ended September 30, 2010, the non-guarantor Subsidiaries generated all of the Issuer’s consolidated total revenue. In addition, as of September 30, 2010, the non-guarantor Subsidiaries held substantially all of the Issuer’s consolidated total assets.

Any entity that makes a payment under its Guarantee will be 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.

The obligations of each Guarantor under its Guarantee will be limited as necessary to prevent the Guarantee from constituting a fraudulent conveyance under applicable law. However, this limitation may not be effective to prevent a Guarantee from being voided under fraudulent conveyance law, or may reduce or eliminate a Guarantor’s obligation to an amount that effectively makes its Guarantee worthless.

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 Related to the Notes — The liabilities of each of EFH Corp. and EFCH currently exceed its assets as shown on its most recent quarterly balance sheet. If a court were to find that EFH Corp., EFCH or EFIH were insolvent before or after giving effect to the offering of the notes and did not receive reasonably equivalent value or fair consideration for the issuance of the notes or the incurrence of a guarantee or the pledge of the Collateral, as applicable, the court may void all or a portion of the obligations represented by the notes or the guarantee of the notes by EFCH or EFIH or the pledge of the Collateral by EFIH as a fraudulent conveyance.”

Subject to “— Certain Covenants — Restrictions on Permitted Asset Transfers,” 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, wind-up, consolidation 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, except that the Guarantee by EFIH shall only be released and discharged as provided under “— Certain Covenants — Restrictions on Permitted Asset Transfers”;

(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

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(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.

Further, the Guarantee by EFCH shall automatically be released in connection with a Permitted Asset Transfer made in accordance with “— Certain Covenants — Restrictions on Permitted Asset Transfers” other than a merger, wind-up or consolidation of EFIH into the Issuer where EFCH continues to be a Subsidiary of the Issuer.

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. Each of the Guarantors is also a holding company for its Subsidiaries. See the risk factor entitled “EFH Corp. is a holding company and its obligations are structurally subordinated to existing and future liabilities and preferred stock of its subsidiaries.”

Paying Agent and Registrar for the Notes

The Issuer will maintain one or more paying agents for the Notes. As of the date of this prospectus, the paying agent for the Notes is the Trustee at its offices in Houston, Texas.

The Issuer will also maintain a registrar. As of the date of this prospectus, the registrar is the Trustee at its offices in Houston, Texas. 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.

Principal, Maturity and Interest

As of the date of this prospectus, $1,060,757,000 aggregate principal amount of the Notes are outstanding. The Notes will mature on January 15, 2020. Subject to compliance with the covenants described under “— Certain Covenants — Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “— Certain Covenants — Liens,” the Issuer may issue additional Notes from time to time after the Issue Date under the Indenture (any such Notes, “Additional Notes”). The 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. Unless the context requires otherwise, references to “Notes” for all purposes of the Indenture and this “Description of the Notes” section include any Additional Notes that are actually issued.

Interest on the Notes will accrue at the rate of 10.000% per annum and will be payable semi-annually in arrears on each January 15 and July 15, commencing on July 15, 2010, to the Holders of record on the immediately preceding January 1 and July 1. Interest on the Notes will accrue from the most recent date to which interest has been paid. Interest on the Notes will be computed on the basis of a 360-day year comprised of twelve 30-day months.

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 of Houston and State of Texas 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 Houston, Texas will be the office of the Trustee maintained for such purpose.

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Additional Interest

Additional Interest may accrue on the Notes in certain circumstances pursuant to the Registration Rights Agreement. All references in the Indenture, in any context, to any interest or other amount payable on or with respect to the Notes shall be deemed to include any Additional Interest pursuant to the Registration Rights Agreement.

Mandatory Redemption; Offers to Purchase; Open Market Purchases

The Issuer will not be 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 “— 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.

Optional Redemption

Except as set forth below, the Issuer will not be entitled to redeem Notes at its option prior to January 15, 2015.

At any time prior to January 15, 2015, the Issuer may redeem all or a part of the 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 Notes or otherwise in accordance with the procedures of DTC, at a redemption price equal to 100% of the principal amount of the Notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest and Additional Interest, if any, to, the date of redemption (the “Redemption Date”), subject to the rights of Holders of Notes on the relevant record date to receive interest due on the relevant interest payment date.

On and after January 15, 2015, the Issuer may redeem the 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 Notes or otherwise in accordance with the procedures of DTC, at the redemption prices (expressed as percentages of principal amount of the Notes to be redeemed) set forth below, plus accrued and unpaid interest and Additional Interest, if any, to the applicable Redemption Date, subject to the right of Holders of 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 January 15 of each of the years indicated below:

Year	Percentage
2015		105.000	%
2016		103.333	%
2017		101.667	%
2018 and thereafter		100.000	%

In addition, until January 15, 2013, the Issuer may, at its option, on one or more occasions redeem up to 35% of the aggregate principal amount of Notes at a redemption price equal to 110.000% of the aggregate principal amount thereof, plus accrued and unpaid interest and Additional Interest, if any, to the applicable Redemption Date, subject to the right of Holders of 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 Notes issued under the Indenture and the original principal amount of any Additional Notes issued under the Indenture after the Issue Date remains outstanding immediately after the occurrence of each such redemption; andprovided, further that each such redemption occurs within 90 days of the date of closing of each such Equity Offering.

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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 Notes, the Trustee shall select the Notes to be redeemed in the manner described under “— Repurchase at the Option of Holders — Selection and Notice.”

Security for the Notes

Collateral Trustee

EFIH has appointed The Bank of New York Mellon Trust Company, N.A. to serve as the collateral trustee (the “Collateral Trustee”) for the benefit of the holders of the Secured Debt Obligations outstanding from time to time.

The Security Documents provide that the Collateral Trustee will be subject to such directions as may be given it by the Trustee and by any other Parity Lien Debt Representatives from time to time as required or permitted by the Indenture and the other Parity Lien Debt Documents. The relative rights with respect to control of the Collateral Trustee are specified in the collateral trust agreement dated as of November 16, 2009 by and among EFIH, the trustees for the 9.75% Notes and the EFIH Notes, any other Parity Lien Debt Representatives, any Junior Lien Debt Representatives and the Collateral Trustee (the “Collateral Trust Agreement”). The Collateral Trustee and the Trustee for the benefit of the Holders of the Notes have entered into a Joinder to the Collateral Trust Agreement, and the Notes have been designated as “Parity Lien Debt” by EFIH. Except as provided in the Collateral Trust Agreement or as directed by an Act of Required Debtholders, the Collateral Trustee will not be obligated:

(1) to act upon directions purported to be delivered to it by any other Person;

(2) to foreclose upon or otherwise enforce any Lien; or

(3) to take any other action whatsoever with regard to any or all of the Security Documents, the Liens created thereby or the Collateral.

Collateral

The Indenture and the Security Documents provide that the Guarantee of the Notes by EFIH, together with any other Parity Lien Debt (which as of the date of this prospectus includes EFIH’s guarantee of the 9.75% Notes, the EFIH Notes and the EFIH 10.000% Notes), are secured on an equal and ratable basis by first-priority security interests granted to the Collateral Trustee, in all of the following property of EFIH:

(1) any Equity Interests it owned as of the Issue Date or may thereafter acquire in any Oncor Subsidiary and any promissory notes or other Indebtedness owed by, or other Investments in, any Oncor Subsidiary that it owned as of the Issue Date or it may thereafter acquire;

(2) all proceeds of, income and other payments (including, without limitation, dividends and distributions received) now or hereafter due and payable with respect to, and supporting obligations relating to, any and all of the foregoing, which, in the case of cash dividends and distributions received by EFIH from Oncor Holdings may be used by EFIH for any purpose not prohibited by the Indenture so long as no Event of Default and no event of default under any other Parity Lien Debt, including the 9.75% Notes, the EFIH Notes and the EFIH 10.000% Notes, shall have occurred and be continuing; and

(3) any Asset Sale Cash Collateral Account established pursuant to the Indenture, the 9.75% Notes Indenture or the EFIH Indenture.

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In addition, any Successor EFIH Company (including the Issuer, if EFIH is merged with and into the Issuer) will grant a first-priority security interest to the Collateral Trustee for the benefit of Holders of the Notes and holders of the other Parity Lien Debt and a second-priority security interest to the Collateral Trustee for the benefit of holders of Junior Lien Debt to the extent that such Successor EFIH Company holds any Equity Interests in, or Indebtedness of, or other Investments in, any Oncor Subsidiary following a Permitted Asset Transfer made in accordance with the covenants described under “— Certain Covenants — Restrictions on Permitted Asset Transfers” and “— Certain Covenants — Restrictions on Certain Investments in Oncor Subsidiaries.”

As of the date of this prospectus, the Collateral consists of a pledge of all of the membership interests EFIH owns in Oncor Holdings. Oncor Holdings owns approximately 80% of Oncor Electric Delivery’s outstanding membership interests. On November 16, 2009, EFIH and the Collateral Trustee entered into a pledge agreement (the “Pledge Agreement”), whereby the Collateral was pledged in favor of the Collateral Trustee for the benefit of the Collateral Trustee, the trustees for the 9.75% Notes and the EFIH Notes and the holders of the 9.75% Notes and the EFIH Notes and the holders of any other Secured Debt Obligations that may be issued in accordance with the Indenture and the 9.75% Notes Indenture and the EFIH Indenture (including the EFIH 10.000% Notes). As a result of the Joinder to the Collateral Trust Agreement and the designation by EFIH referred to above, the Trustee and the holders of the Notes will benefit from the pledge of the Collateral under the Pledge Agreement. The Collateral does not consist of any assets of any Oncor Subsidiary. See “Risk Factors — Risks Related to the Notes — The notes are secured only to the extent of the value of the assets that have been granted as security for EFIH’s guarantee of the notes”; “— Regulatory approvals may be required in order to enforce the security interests in the Collateral and to dispose of an interest in, or operational control of, the Collateral that secures EFIH’s guarantee of the notes”; “— In the event of EFH Corp.’s bankruptcy, the ability of the holders of the notes to realize upon the Collateral securing EFIH’s guarantee of the notes will be subject to certain bankruptcy law limitations”; and “— The value of the Collateral may be diluted if we issue additional debt that is secured equally and ratably by the same Collateral securing the guarantee by EFIH of the notes or if the Collateral is sold.”

No appraisal of the value of the Collateral has been made in connection with the issuance of the Notes and the value of the Collateral in the event of liquidation will depend on many factors. Consequently, liquidating the Collateral may not produce proceeds in an amount sufficient to pay any amounts due on the Secured Debt Obligations, including the Notes.

The fair market value of the Collateral is subject to fluctuations based on factors that include, among others, the ability to sell the Collateral in an orderly sale, general economic conditions, the availability of buyers and similar factors. The amount to be received upon a sale of the Collateral would be dependent on numerous factors, including but not limited to the actual fair market value of the Collateral at such time and the timing and the manner of the sale. By its nature, the Collateral may be illiquid and may have no readily ascertainable market value. In the event of a foreclosure, liquidation, bankruptcy or similar proceeding, we cannot assure you that the proceeds from any sale or liquidation of the Collateral will be sufficient to pay the Parity Lien Obligations, including the Notes. Any claim for the difference between the amount, if any, realized by Holders of the Notes from the sale of Collateral securing the Secured Debt Obligations will rank equally in right of payment with all of our other unsecured unsubordinated Indebtedness and other obligations, including trade payables.

So long as no Event of Default and no event of default under any other Parity Lien Debt, including the 9.75% Notes, the EFIH Notes and the EFIH 10.000% Notes, shall have occurred and be continuing, and subject to certain terms and conditions, EFIH will be entitled to exercise any voting and other consensual rights pertaining to the Collateral (other than as set forth in the Pledge Agreement and the other Security Documents). The Pledge Agreement requires EFIH to deliver to the Collateral Trustee, for the Collateral Trustee to maintain in its possession, certificates, if any, evidencing the Collateral. Upon the occurrence and during the continuance of an Event of Default under the Notes, to the extent permitted by law and subject to the provisions of the Pledge Agreement, all of the rights of EFIH to exercise voting or other consensual rights with respect to the Collateral will cease, and all such rights will become vested in the Collateral Trustee, which, to the extent permitted by law, will have the sole right to exercise such voting and other consensual rights.

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Certain Bankruptcy Limitations

The right of the Collateral Trustee to repossess and dispose of the Collateral upon the occurrence of an Event of Default would be significantly impaired by applicable bankruptcy law in the event that a bankruptcy case were to be commenced by or against EFIH prior to the Collateral Trustee having repossessed and disposed of the Collateral. Upon the commencement of a case for relief under Title 11 of the United States Code, as amended (the “Bankruptcy Code”), a secured creditor such as the Collateral Trustee is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of security repossessed from the debtor, without bankruptcy court approval.

In view of the broad equitable powers of a U.S. bankruptcy court, it is impossible to predict how long payments under the Notes could be delayed following commencement of a bankruptcy case, whether or when the Collateral Trustee could repossess or dispose of the Collateral, the value of the Collateral at the time of the bankruptcy petition or whether or to what extent Holders of the Notes would be compensated for any delay in payment or loss of value of the Collateral. The Bankruptcy Code permits only the payment and/or accrual of post-petition interest, costs and attorneys’ fees to a secured creditor during a debtor’s bankruptcy case to the extent the value of the Collateral is determined by the bankruptcy court to exceed the aggregate outstanding principal amount at maturity of the obligations secured by the Collateral. There can be no assurance that the value of the Collateral will exceed the outstanding principal amount of the Notes and the other Parity Lien Debt Obligations, including the 9.75% Notes, the EFIH Notes and the EFIH 10.000% Notes.

Furthermore, in the event a bankruptcy court determines that the value of the Collateral is not sufficient to repay all amounts due on the Notes and the other Parity Lien Debt Obligations, including the 9.75% Notes, the EFIH Notes and the EFIH 10.000% Notes, the Holders of the Notes and the holders of the other Parity Lien Debt would hold secured claims to the extent of the value of the Collateral to which the Holders of the Notes and the holders of the other Parity Lien Debt are entitled, and unsecured claims with respect to any such shortfall.

Additional Parity Lien Debt

As of the date of this prospectus, $115 million principal amount of the 9.75% Notes have been issued by the Issuer, and $141 million principal amount of EFIH Notes and $2,180 million principal amount of EFIH 10.000% Notes have been issued by EFIH and EFIH Finance Inc., all of which constitutes Parity Lien Debt, and all of which is secured by the Collateral on an equal and ratable basis with the Notes. In addition, the Indenture and the Security Documents provide that the Issuer and EFIH may incur additional Parity Lien Debt as permitted by the covenants described under “— Certain Covenants — Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “— Certain Covenants — Liens,” by issuing Additional Notes under the Indenture or under one or more additional indentures or incurring other Indebtedness secured by Parity Liens on the Collateral. All additional Parity Lien Debt is or will be secured equally and ratably with EFIH’s Guarantee of the Notes by Liens on the Collateral held by the Collateral Trustee for as long as EFIH’s Guarantee of the Notes is secured by the Collateral. The Collateral Trustee under the Collateral Trust Agreement will hold all Parity Liens in trust for the benefit of the Holders of the Notes, the 9.75% Notes, the EFIH Notes, the EFIH 10.000% Notes and the holders of any future Parity Lien Debt and all other Parity Lien Obligations. Additional Parity Lien Debt will be permitted to be secured by the Collateral only if such Parity Lien Debt and the related Parity Liens are permitted to be incurred under the covenants described under “— Certain Covenants — Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “— Certain Covenants — Liens.” The agent or representative of any Parity Lien Debt will become a party to the Security Documents by joinder agreement.

Future Junior Lien Debt

The Indenture and the Security Documents provide that the Issuer and EFIH may incur Junior Lien Debt in the future by issuing debt securities under one or more indentures, incurring Indebtedness under Credit Facilities or otherwise issuing or increasing a new Series of Secured Lien Debt secured by Junior Liens on the Collateral. Junior Lien Debt will be permitted to be secured by the Collateral only if such Junior Lien Debt and the related Junior Liens are permitted to be incurred under the covenants described under “— Certain Covenants — Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “— Certain Covenants — Liens.” The Collateral Trustee under the Collateral Trust Agreement will hold all Junior Liens in trust for the benefit of the holders of any Junior Lien Debt and all other Junior Lien Obligations. The agent or representative of any Junior Lien Obligations shall become a party to the Collateral Trust Agreement by joinder agreement.

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Enforcement of Liens

If the Collateral Trustee at any time receives written notice stating that any event has occurred that constitutes a default under any Secured Debt Document entitling the Collateral Trustee to foreclose upon, collect or otherwise enforce its Liens thereunder, it will promptly deliver written notice thereof to each Secured Debt Representative. Thereafter, the Collateral Trustee will await direction by an Act of Required Debtholders and will act, or decline to act, as directed by an Act of Required Debtholders, in the exercise and enforcement of the Collateral Trustee’s interests, rights, powers and remedies in respect of the Collateral or under the Security Documents or applicable law and, following the initiation of such exercise of remedies, the Collateral Trustee will act, or decline to act, with respect to the manner of such exercise of remedies as directed by an Act of Required Debtholders. Unless it has been directed to the contrary by an Act of Required Debtholders, the Collateral Trustee in any event may (but will not be obligated to) take or refrain from taking such action with respect to any default under any Secured Debt Document as it may deem advisable to preserve and protect the value of the Collateral.

Until the Discharge of Parity Lien Obligations, the Holders of the Notes and the holders of other Parity Lien Obligations will have, subject to the exceptions set forth below in clauses (1) through (4), the exclusive right to authorize and direct the Collateral Trustee with respect to the Security Documents and the Collateral (including, without limitation, the exclusive right to authorize or direct the Collateral Trustee to enforce, collect or realize on any Collateral or exercise any other right or remedy with respect to the Collateral) and neither the provisions of the Security Documents relating thereto (other than in accordance with the Collateral Trust Agreement) nor any Junior Lien Representative or holder of Junior Lien Obligations, if any, may authorize or direct the Collateral Trustee with respect to such matters. Notwithstanding the foregoing, the holders of Junior Lien Obligations may direct the Collateral Trustee with respect to such matters:

(1) without any condition or restriction whatsoever, at any time after the Discharge of Parity Lien Obligations;

(2) to deliver any notice or demand necessary to enforce (subject to the prior Discharge of Parity Lien Obligations) any right to claim, take or receive proceeds of Collateral remaining after the Discharge of Parity Lien Obligations;

(3) as necessary to perfect or establish the priority (subject to Parity Liens) of the Junior Liens upon any Collateral;provided that, unless otherwise agreed to by the Collateral Trustee in the Security Documents, the holders of Junior Lien Obligations may not require the Collateral Trustee to take any action to perfect any Collateral through possession or control (other than the Collateral Trustee as agent for the benefit of the Parity Lien Representative and holders of the Parity Lien Obligations agreeing pursuant to the Collateral Trust Agreement to act as bailee for the Collateral Trustee as agent for the benefit of the Junior Lien Representatives and holders of the Junior Lien Obligations); or

(4) as necessary to create, prove, preserve or protect (but not enforce) the Junior Liens upon any Collateral.

Both before and during an insolvency or liquidation proceeding until the Discharge of Parity Lien Obligations, none of the holders of Junior Lien Obligations, the Collateral Trustee (unless acting pursuant to an Act of Required Debtholders) or any Junior Lien Representative will be permitted to:

(1) request judicial relief, in an insolvency or liquidation proceeding or in any other court, that would hinder, delay, limit or prohibit the lawful exercise or enforcement of any right or remedy otherwise available to the holders of Parity Lien Obligations in respect of the Parity Liens or that would limit, invalidate, avoid or set aside any Parity Lien or subordinate the Parity Liens to the Junior Liens or grant the Junior Liens equal ranking to the Parity Liens;

(2) oppose or otherwise contest any motion for (A) relief from the automatic stay or (B) any injunction against foreclosure or (C) any enforcement of Parity Liens, in each case made by any holder of Parity Lien Obligations or any Parity Lien Representative in any insolvency or liquidation proceeding;

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(3) oppose or otherwise contest any lawful exercise by any holder of Parity Lien Obligations or any Parity Lien Representative of the right to credit bid Parity Lien Obligations at any sale of Collateral in the foreclosure of Parity Liens;

(4) oppose or otherwise contest any other request for judicial relief made in any court by any holder of Parity Lien Obligations or any Parity Lien Representative relating to the lawful enforcement of any Parity Lien; or

(5) challenge the validity, enforceability, perfection or priority of the Parity Liens with respect to the Collateral.

Notwithstanding the foregoing, both before and during an insolvency or liquidation proceeding, the holders of Junior Lien Obligations or Junior Lien Representatives may take any actions and exercise any and all rights that would be available to a holder of unsecured claims, including, without limitation, the commencement of an insolvency or liquidation proceeding against EFIH in accordance with applicable law;provided the Collateral Trust Agreement provides that no holder of Junior Lien Obligations or Junior Lien Representative will be permitted to take any of the actions prohibited by clauses (1) through (5) of the preceding paragraph or oppose or contest any order that it has agreed not to oppose or contest under the provisions described under “— Insolvency or Liquidation Proceedings.”

At any time prior to the Discharge of Parity Lien Obligations and after (1) the commencement of any insolvency or liquidation proceeding in respect of EFIH or (2) the Collateral Trustee and each Junior Lien Representative have received written notice from any Parity Lien Representative stating that (A) any Series of Parity Lien Debt has become due and payable in full (whether at maturity, upon acceleration or otherwise) or (B) the holders of Parity Liens securing one or more Series of Parity Lien Debt have become entitled under any Parity Lien Document to and desire to enforce any or all of the Parity Liens by reason of a default under such Parity Lien Documents, no payment of money (or the equivalent of money) will be made from the proceeds of Collateral by EFIH to the Collateral Trustee (other than distributions to the Collateral Trustee in respect of its fees under the Collateral Trust Agreement and for the benefit of the holders of Parity Lien Obligations), any Junior Lien Representative or any holder of Junior Lien Obligations (including, without limitation, payments and prepayments made for application to Junior Lien Obligations).

All proceeds of Collateral received by any Junior Lien Representative or any holder of Junior Lien Obligations in violation of the immediately preceding paragraph will be held by such Person in trust for the account of the holders of Parity Lien Obligations and remitted to any Parity Lien Representative upon demand by such Parity Lien Representative. The Junior Liens will remain attached to and, subject to the provisions described under “— Provisions of the Indenture Relating to Security — Ranking of Parity Liens,” enforceable against all proceeds so held or remitted. All proceeds of Collateral received by any Junior Lien Representative or any holder of Junior Lien Obligations not in violation of the immediately preceding paragraph will be received by such Person free from the Parity Liens.

Pursuant to the Public Utility Regulatory Act (“PURA”), Texas Utilities Code §§39.262(l) and 39.915 and, through October 10, 2012, to the Order on Rehearing in Public Utility Commission of Texas (“PUCT”) Docket No. 34077, the PUCT must approve any change in majority ownership, controlling ownership or operational control of Oncor Electric Delivery. As a result, prior to any foreclosure on the Collateral consisting of membership interests in Oncor Holdings, approval of the PUCT will be required if such foreclosure consists of a change in majority ownership or control of Oncor Holdings. Pursuant to PURA §§39.262(m) and 39.915(b), the PUCT will approve such a transfer if it finds that the transaction is in the public interest. In making its determination, these sections of PURA provide that the PUCT will consider whether the transaction will adversely affect the reliability of service, availability of service or cost of service of Oncor Electric Delivery. We cannot assure you that such approval will be granted and, if it is not granted, the Collateral Trustee may not be able to liquidate the Collateral consisting of membership interests and, accordingly, the Collateral Trustee may not be able to distribute any proceeds to Holders of the Notes upon such foreclosure. If the approval is granted, then PUCT approval would also be required with respect to any subsequent disposition of a majority or controlling interest in the membership interests of Oncor Holdings.

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In addition, pursuant to the terms of an investor rights agreement among the Issuer, Oncor Holdings, Oncor Electric Delivery and the minority investor in Oncor Electric Delivery, a transfer of the Equity Interests in Oncor Holdings to a third party, including as a result of any enforcement of the Lien on the Collateral consisting of Equity Interests of Oncor Holdings or Oncor Electric Delivery, may give rise to a tag-along right of the minority investor(s) in Oncor Electric Delivery to participate in that transfer on a pro rata basis.

Waiver of Right of Marshalling

The Collateral Trust Agreement provides that, prior to the Discharge of Parity Lien Obligations, the holders of Junior Lien Obligations, each Junior Lien Representative and the Collateral Trustee may not assert or enforce any right of marshalling accorded to a junior lienholder, as against the holders of Parity Lien Obligations and the Parity Lien Representatives (in their capacity as senior or priority lienholders) with respect to the Collateral. Following the Discharge of Parity Lien Obligations, the holders of Junior Lien Obligations and any Junior Lien Representative may assert their right under the Uniform Commercial Code or otherwise to any proceeds remaining following a sale or other disposition of Collateral by, or on behalf of, the holders of Parity Lien Obligations.

Insolvency or Liquidation Proceedings

If in any insolvency or liquidation proceeding and prior to the Discharge of Parity Lien Obligations, the holders of Parity Lien Obligations by an Act of Required Debtholders consent to any order:

(1) for use of cash collateral;

(2) approving a debtor-in-possession financing secured by a Lien that is senior to or on a parity with all Parity Liens upon any property of the estate in such insolvency or liquidation proceeding;

(3) granting any relief on account of Parity Lien Obligations as adequate protection (or its equivalent) for the benefit of the holders of Parity Lien Obligations in the Collateral; or

(4) relating to a sale of assets of EFIH that provides, to the extent the Collateral sold is to be free and clear of Liens, that all Parity Liens and Junior Liens will attach to the proceeds of the sale;

then, the holders of Junior Lien Obligations and the Junior Lien Representatives will not oppose or otherwise contest the entry of such order;provided, that the holders of Junior Lien Obligations or a Junior Lien Representative may request the grant to the Collateral Trustee, for the benefit of the holders of Junior Lien Obligations and the Junior Lien Representatives, of a Junior Lien upon any property on which a Lien is (or is to be) granted under such order to secure the Parity Lien Obligations, co-extensive in all respects with, but subordinated, as provided in the provisions described under “— Provisions of the Indenture Relating to Security — Ranking of Parity Liens,” to, such Lien and all Parity Liens on such property. The holders of Parity Lien Obligations (including the Holders of the Notes) and the Parity Lien Representatives (including the Trustee) will agree not to oppose or otherwise contest in any respect any request made by the Junior Lien Representatives for a Junior Lien pursuant to the proviso to the preceding sentence.

Notwithstanding the foregoing, both before and during an insolvency or liquidation proceeding, the holders of Junior Lien Obligations and the Junior Lien Representatives may take any actions and exercise any and all rights that would be available to a holder of unsecured claims, including, without limitation, the commencement of insolvency or liquidation proceedings against EFIH in accordance with applicable law;provided that the Collateral Trust Agreement provides that no holder of Junior Lien Obligations or Junior Lien Representative will be permitted to take any of the actions prohibited under the third and fourth paragraphs of the provisions described under “— Enforcement of Liens,” or oppose or contest any order that it has agreed not to oppose or contest under clauses (1) through (4) of the preceding paragraph.

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Neither the holders of Junior Lien Obligations nor any Junior Lien Representative will file or prosecute in any insolvency or liquidation proceeding any motion for adequate protection (or any comparable request for relief) based upon their interest in the Collateral under the Junior Liens, except that:

(1) they may freely seek and obtain relief granting a Junior Lien co-extensive in all respects with, but subordinated, as provided in the provisions described under “— Provisions of the Indenture Relating to Security — Ranking of Parity Liens,” to, all Liens granted in such insolvency or liquidation proceeding to, or for the benefit of, the holders of Parity Lien Obligations; and

(2) they may freely seek and obtain any relief upon a motion for adequate protection (or any comparable relief), without any condition or restriction whatsoever, at any time after the Discharge of Parity Lien Obligations.

Order of Application

The Collateral Trust Agreement provides that if any Collateral is sold or otherwise realized upon by the Collateral Trustee in connection with any foreclosure, collection or other enforcement of Liens granted to the Collateral Trustee in the Security Documents, the proceeds received by the Collateral Trustee from such foreclosure, collection or other enforcement will be distributed by the Collateral Trustee in the following order of application:

FIRST, to the payment of all amounts payable under the Collateral Trust Agreement on account of the Collateral Trustee’s fees and any reasonable legal fees, costs and expenses or other liabilities of any kind incurred by the Collateral Trustee or any co-trustee or agent of the Collateral Trustee in connection with any Security Document;

SECOND, ratably to the respective Parity Lien Representatives for application, after payment of any fees and expenses (including but not limited to, attorney’s fees and expenses) of such Parity Lien Representative, to the payment of all outstanding Notes and other Parity Lien Debt and any other Parity Lien Obligations that are then due and payable in such order as may be provided in the relevant Parity Lien Documents in an amount sufficient to pay in full in cash all outstanding Notes and other Parity Lien Debt and all other Parity Lien Obligations that are then due and payable (including all interest accrued thereon after the commencement of any insolvency or liquidation proceeding at the rate, including any applicable post-default rate, specified in the relevant Parity Lien Documents, even if such interest is not enforceable, allowable or allowed as a claim in such proceeding, and including the discharge or cash collateralization (at the lower of (1) 105% of the aggregate undrawn amount and (2) the percentage of the aggregate undrawn amount required for release of Liens under the terms of the applicable Parity Lien Document) of all outstanding letters of credit constituting Parity Lien Debt);

THIRD, to the respective Junior Lien Representatives for application to the payment of all outstanding Junior Lien Debt and any other Junior Lien Obligations that are then due and payable in such order as may be provided in the Junior Lien Documents in an amount sufficient to pay in full in cash all outstanding Junior Lien Debt and all other Junior Lien Obligations that are then due and payable (including all interest accrued thereon after the commencement of any insolvency or liquidation proceeding at the rate, including any applicable post-default rate, specified in the Junior Lien Documents, even if such interest is not enforceable, allowable or allowed as a claim in such proceeding, and including the discharge or cash collateralization (at the lower of (1) 105% of the aggregate undrawn amount and (2) the percentage of the aggregate undrawn amount required for release of Liens under the terms of the applicable Junior Lien Document) of all outstanding letters of credit, if any, constituting Junior Lien Debt); and

FOURTH, any surplus remaining after the payment in full in cash of the amounts described in the preceding clauses will be paid to EFIH, or its successors or assigns, or as a court of competent jurisdiction may direct.

If any Junior Lien Representative or any holder of a Junior Lien Obligation collects or receives any proceeds in respect of any foreclosure, collection or other enforcement to which it was not entitled pursuant to the terms of the immediately preceding paragraphs, whether after the commencement of an insolvency or liquidation proceeding or otherwise, such Junior Lien Representative or such holder of a Junior Lien Obligation, as the case may be, will forthwith deliver the same to the Collateral Trustee to be applied in accordance with the provisions set forth in the immediately preceding paragraphs. Until so delivered, such proceeds will be held by that Junior Lien Representative or that holder of a Junior Lien Obligation, as the case may be, in trust for the benefit of the holders of the Parity Lien Obligations. These provisions will not apply to payments received by any holder of Junior Lien Obligations if such payments are not proceeds of, or the result of a realization upon, Collateral.

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The provisions set forth above under this “Order of Application” caption are intended for the benefit of, and will be enforceable as a third party beneficiary by, each present and future holder of Secured Debt Obligations, each present and future Secured Debt Representative and the Collateral Trustee as holder of Parity Liens and Junior Liens. The Issuer and EFIH will be required to cause the Secured Debt Representative of each future Series of Secured Lien Debt to deliver a joinder to the Collateral Trust Agreement, including a Lien Sharing and Priority Confirmation, to the Collateral Trustee and each other Secured Debt Representative at the time of incurrence of such Series of Secured Lien Debt.

In connection with the application of proceeds in accordance with the provisions set forth above under this “Order of Application” caption, except as otherwise directed by an Act of Required Debtholders, the Collateral Trustee may sell any non-cash proceeds for cash prior to the application of the proceeds thereof.

Release of Security Interests

The Security Documents provide that the Collateral will be released:

1. in whole, upon (a) payment in full of all outstanding Secured Debt Obligations at the time such debt is paid in full and (b) termination or expiration of all commitments to extend credit under all Secured Debt Documents and the cancellation or termination or cash collateralization in an account maintained by the Collateral Trustee (at the lower of (1) 105% of the aggregate undrawn amount and (2) the percentage of the aggregate undrawn amount required for release of Liens under the terms of the applicable Secured Debt Documents) of all outstanding letters of credit issued pursuant to any Secured Debt Documents;provided that the Issuer has delivered an Officer’s Certificate to the Collateral Trustee certifying that the conditions described in this paragraph 1. have been met and that such release of the Collateral does not violate the terms of any applicable Secured Debt Document;

2. with respect to the Note Obligations only, upon satisfaction and discharge of the Indenture as set forth under “— Satisfaction and Discharge”;

3. with respect to the Note Obligations only, upon a Legal Defeasance or Covenant Defeasance as set forth under “— Legal Defeasance and Covenant Defeasance”;

4. with respect to the Note Obligations only, upon payment in full of the Notes and all other Note Obligations that are outstanding, due and payable at the time the Notes are paid in full;

5. with respect to any Secured Debt Obligations (other than Note Obligations) only, upon payment in full of such Secured Lien Debt and all other Secured Debt Obligations in respect thereof that is outstanding, due and payable at the time such Secured Lien Debt is paid in full;

6. as to a release of all or substantially all of the Collateral, if (a) consent to the release of that Collateral has been given by holders of 66²/3% of the aggregate principal amount of Parity Lien Debt at the time outstanding voting together as one class, as provided for in the applicable Secured Debt Documents;provided that if an Event of Default under the Notes or an event of default with respect to any other Secured Lien Debt has occurred and is continuing at the time of the solicitation of any such consent, the consent of holders of 66²/3% of the aggregate principal amount of Secured Lien Debt at the time outstanding voting together as one class shall also be required, and (b) EFIH has delivered an Officer’s Certificate to the Collateral Trustee certifying that any such necessary consents have been obtained and that such release of the Collateral does not violate the terms of any applicable Secured Debt Document;

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7. as to a release of less than all or substantially all of the Collateral, if (A) consent to the release of all Parity Liens (or, at any time after the Discharge of Parity Lien Obligations, consent to the release of all Junior Liens) on such Collateral has been given by holders of a majority of the aggregate principal amount of Parity Lien Debt at the time outstanding voting as one class, as provided for in the Parity Lien Documents (or, at any time after the Discharge of Parity Lien Obligations, holders of a majority of the aggregate principal amount of the Junior Lien Debt at the time outstanding voting together as one class, as provided for in the Junior Lien Documents) and (B) EFIH has delivered an Officer’s Certificate to the Collateral Trustee certifying that any such necessary consents have been obtained and that such release of the Collateral does not violate the terms of any applicable Secured Debt Document;

8. as to any Collateral that is sold, transferred or otherwise disposed of by EFIH in a transaction or other circumstance that is not prohibited by the terms of any applicable Secured Debt Document, at the time of, or immediately prior to, such sale, transfer or other disposition;provided that EFIH has delivered an Officer’s Certificate to the Collateral Trustee certifying that any such sale, transfer or other disposition does not violate the terms of any applicable Secured Debt Document; or

9. with respect to the Note Obligations only, in whole or in part, with the consent of the Holders of the requisite percentage of Notes in accordance with the provisions described under “— Amendment, Supplement and Waiver,” and upon delivery of instructions and any other documentation, in each case as required by the Indenture and the Security Documents, in a form satisfactory to the Collateral Trustee.

Upon compliance by EFIH with the conditions precedent set forth above, the Collateral Trustee will promptly cause to be released and reconveyed to EFIH the released Collateral.

Amendment

The Collateral Trust Agreement provides that no amendment or supplement to the provisions of the Collateral Trust Agreement or any other Security Document will be effective without the approval of the Collateral Trustee acting as directed by an Act of Required Debtholders, except that:

(1) any amendment or supplement that has the effect solely of (a) adding or maintaining Collateral, securing additional Secured Lien Debt that was otherwise permitted by the terms of the Secured Debt Documents to be secured by the Collateral or preserving, perfecting or establishing the priority of the Liens thereon or the rights of the Collateral Trustee therein; (b) curing any ambiguity, defect or inconsistency; (c) providing for the assumption of the obligations of EFIH under any Security Document in the case of a merger or consolidation or sale of all or substantially all of the assets of EFIH; or (d) making any change that would provide any additional rights or benefits to the holders of Secured Debt Obligations, the Secured Debt Representatives or the Collateral Trustee or that does not adversely affect the legal rights under any Secured Debt Document of any holder of Secured Debt Obligations, the Secured Debt Representatives or the Collateral Trustee, will, in each case, become effective when executed and delivered by EFIH and the Collateral Trustee;

(2) no amendment or supplement that reduces, impairs or adversely affects the right of any holder of Secured Debt Obligations:

(a) to vote its outstanding Secured Lien Debt as to any matter described as subject to an Act of Required Debtholders or direction by the Required Parity Lien Debtholders or Required Junior Lien Debtholders (or amends the provisions of this clause (2) or the definition of “Act of Required Debtholders,” “Required Parity Lien Debtholders” or “Required Junior Lien Debtholders”);

(b) to share in the order of application described under “— Order of Application” in the proceeds of enforcement of or realization on any Collateral that has not been released in accordance with the provisions described under “— Release of Security Interests”; or

(c) to require that Liens securing Secured Debt Obligations be released only as set forth in the provisions described under “— Release of Security Interests”

will become effective without the consent of the requisite percentage or number of holders of each Series of Secured Lien Debt so affected under the applicable Secured Debt Documents; and

(3) no amendment or supplement that imposes any obligation upon the Collateral Trustee or any Secured Debt Representative or adversely affects the rights of the Collateral Trustee, as determined by the Collateral Trustee in its sole discretion, or any Secured Debt Representative, respectively, in its individual capacity as such will become effective without the consent of the Collateral Trustee or such Secured Debt Representative, respectively.

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Notwithstanding the foregoing clause (1), but subject to clauses (2) and (3) above:

(1) any Security Document that secures Junior Lien Obligations (but not Parity Lien Obligations) may be amended or supplemented with the approval of the Collateral Trustee acting as directed in writing by the Required Junior Lien Debtholders, unless such amendment or supplement would not be permitted under the terms of the Collateral Trust Agreement or the other Parity Lien Documents; and

(2) any amendment or waiver of, or any consent under, any provision of the Collateral Trust Agreement or any other Security Document that secures Parity Lien Obligations (except any such amendment, waiver or consent that releases Collateral with respect to which any consent of holders of Junior Lien Debt is required pursuant to the Collateral Trust Agreement, which will be governed by the provisions set forth above) will apply automatically to any comparable provision of any comparable Junior Lien Document without the consent of or notice to any holder of Junior Lien Obligations and without any action by the Issuer or EFIH or any Holder of Notes or holder of other Junior Lien Obligations.

Voting

In connection with any matter under the Collateral Trust Agreement requiring a vote of holders of Secured Lien Debt, each Series of Secured Lien Debt will cast its votes in accordance with the Secured Debt Documents governing such Series of Secured Lien Debt. The amount of Secured Lien Debt to be voted by a Series of Secured Lien Debt will equal (1) the aggregate outstanding principal amount of Secured Lien Debt held by such Series of Secured Lien Debt (including outstanding letters of credit whether or not then available or drawn), plus (2) the aggregate unfunded commitments to extend credit which, when funded, would constitute Indebtedness of such Series of Secured Lien Debt. Following and in accordance with the outcome of the applicable vote under its Secured Debt Documents, the Secured Debt Representative of each Series of Secured Lien Debt will vote the total amount of Secured Lien Debt under that Series of Secured Lien Debt as a block in respect of any vote under the Collateral Trust Agreement.

Provisions of the Indenture Relating to Security

Equal and Ratable Sharing of Collateral by Holders of Parity Lien Debt

The Indenture provides that, notwithstanding:

(1) anything contained in the Collateral Trust Agreement or in any other Security Documents;

(2) the time of incurrence of any Series of Parity Lien Debt;

(3) the order or method of attachment or perfection of any Liens securing any Series of Parity Lien Debt;

(4) the time or order of filing or recording of financing statements or other documents filed or recorded to perfect any Parity Lien upon any Collateral;

(5) the time of taking possession or control over any Collateral;

(6) that any Parity Lien may not have been perfected or may be or have become subordinated, by equitable subordination or otherwise, to any other Lien; or

(7) the rules for determining priority under any law governing relative priorities of Liens,

all Parity Liens granted at any time by EFIH will secure, equally and ratably, all present and future Parity Lien Obligations.

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The foregoing section is intended for the benefit of, and will be enforceable as a third party beneficiary by, each present and future holder of Parity Lien Obligations, each present and future Parity Lien Representative and the Collateral Trustee as holder of Parity Liens.

Ranking of Parity Liens

The Indenture requires the Junior Lien Documents, if any, to provide that, notwithstanding:

(1) anything to the contrary contained in the Security Documents;

(2) the time of incurrence of any Series of Parity Lien Debt;

(3) the order or method of attachment or perfection of any Liens securing any Series of Parity Lien Debt;

(4) the time or order of filing or recording of financing statements or other documents filed or recorded to perfect any Lien upon any Collateral;

(5) the time of taking possession or control over any Collateral;

(6) that any Parity Lien may not have been perfected or may be or have become subordinated, by equitable subordination or otherwise, to any other Lien; or

(7) the rules for determining priority under any law governing relative priorities of Liens,

all Junior Liens at any time granted by EFIH will be subject and subordinate to all Parity Liens securing Parity Lien Obligations.

The Indenture also requires the Junior Lien Documents, if any, to provide that the provisions described in the foregoing clauses (1) through (7) are intended for the benefit of, and will be enforceable as a third party beneficiary by, each present and future holder of Parity Lien Obligations, each present and future Parity Lien Representative and the Collateral Trustee as holder of Parity Liens.

Relative Rights

The Indenture requires that nothing in the Junior Lien Documents will:

(1) impair, as between EFIH and the Holders of the Notes, the obligation of EFIH to pay principal, premium, if any, and interest and Additional Interest, if any, on the Notes in accordance with the terms of its Guarantee thereof or any other obligation of EFIH under the Indenture;

(2) affect the relative rights of Holders of Notes as against any other creditors of EFIH (other than holders of Junior Liens or other Parity Liens);

(3) restrict the right of any Holder of Notes to sue for payments that are then due and owing (but not enforce any judgment in respect thereof against any Collateral to the extent specifically prohibited by the provisions described under “— Security for the Notes — Enforcement of Liens” or “— Security for the Notes — Insolvency or Liquidation Proceedings”);

(4) restrict or prevent any Holder of Notes or holder of other Parity Lien Obligations, the Collateral Trustee or any other Person from exercising any of its rights or remedies upon a Default or Event of Default not specifically restricted or prohibited by the provisions described under “— Security for the Notes — Enforcement of Liens” or “— Security for the Notes — Insolvency or Liquidation Proceedings”; or

(5) restrict or prevent any Holder of Notes or holder of other Parity Lien Obligations, the Trustee, the Collateral Trustee or any other Person from taking any lawful action in an insolvency or liquidation proceeding not specifically restricted or prohibited by the provisions described under “— Security for the Notes — Enforcement of Liens” or “— Security for the Notes — Insolvency or Liquidation Proceedings.”

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Further Assurances

The Indenture and the Security Documents provide that EFIH, at its own expense, will do or cause to be done all acts and things that may be required, or that the Collateral Trustee from time to time may reasonably request, to assure and confirm that the Collateral Trustee holds, for the benefit of the Secured Debt Representatives and holders of Secured Debt Obligations, duly created and enforceable and perfected Liens upon the Collateral (including any property or assets that are acquired or otherwise become Collateral after the Notes are issued), in each case, as contemplated by, and with the Lien priority required under, the Secured Debt Documents.

Upon the reasonable request of the Collateral Trustee or any Secured Debt Representative at any time and from time to time, EFIH, at its own expense, will promptly execute, acknowledge and deliver such security documents, instruments, certificates, notices and other documents, and take such other actions as may be reasonably required, or that the Collateral Trustee may reasonably request, to create, perfect, protect, assure or enforce the Liens and benefits intended to be conferred, in each case as contemplated by the Secured Debt Documents for the benefit of the holders of Secured Debt Obligations.

Impairment of Security Interest

The Pledge Agreement provides that EFIH will not take or omit to take any action which would or could reasonably be expected to have the result of materially adversely affecting or impairing the Liens in favor of the Collateral Trustee, the Trustee and the holders of the Notes with respect to the Collateral. EFIH shall not grant to any Person, or permit any Person to retain (other than the Collateral Trustee), any interest whatsoever in the Collateral, other than pursuant to clause (3) of the definition of “Permitted Liens.” The Issuer and its Restricted Subsidiaries (including EFIH) will not enter into any agreement that requires the proceeds received from any sale of Collateral to be applied to repay, redeem, defease or otherwise acquire or retire any Indebtedness of any Person, other than as permitted by the Indenture, the Notes and the Security Documents. EFIH shall, at its sole cost and expense, execute and deliver all such agreements and instruments as necessary, or as the Trustee shall reasonably request, to more fully or accurately describe the assets and property intended to be Collateral or the obligations intended to be secured by the Pledge Agreement or any other Security Document.

After-Acquired Property

Promptly following the acquisition by EFIH of any Equity Interests in any Oncor Subsidiary or any Indebtedness of, or other Investments in, any Oncor Subsidiary or any property or assets required to be pledged as Collateral pursuant to the covenant described under “— Repurchase at the Option of Holders — Asset Sales” or any Equity Interests in or any Indebtedness of, or other Investments in, any Successor Oncor Business, EFIH will execute and deliver such security instruments, pledges, financing statements and certificates and opinions of counsel as shall be reasonably necessary to vest in the Collateral Trustee a perfected first-priority security interest in such Equity Interests, Indebtedness or other Investments or property or assets and to have such Equity Interests, Indebtedness or other Investments or property or assets added to the Collateral and thereupon all provisions of the Indenture relating to the Collateral shall be deemed to relate to such Equity Interests, Indebtedness or other Investments or property or assets to the same extent and with the same force and effect.

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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 and Additional Interest, if any, 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 under this “— Repurchase at the Option of Holders — Change of Control” section, that a Holder must follow.

Any proceeds received by the Issuer or its Restricted Subsidiaries from a sale, conveyance or disposition of Collateral or other Oncor-related Assets that constitutes a Change of Control shall be subject to a perfected security interest for the benefit of the holders of the Secured Debt Obligations until consummation of the Change of Control Offer.

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.

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;

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(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 a Receivables Facility to be wound down. Additionally, the terms of the 9.75% Notes and certain series of the Existing Notes provide that certain change of control events with respect to the Issuer (including a Change of Control under the Indenture) would result in the Issuer being required to offer to repurchase such Existing Notes of the relevant series.

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. As discussed above, a change in control of EFIH would require regulatory approval by the PUCT under the public interest standard and, through October 10, 2012, the PUCT order. As of the date of this prospectus, we have no present intention to engage in a transaction involving a Change of Control, although it is possible that we could decide to engage in such a transaction 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 will 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, subject to certain exceptions, 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.

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.

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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)(A) 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) except in the case of an Asset Sale of Collateral, 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;provided that the aggregate fair market value of Designated Non-cash Consideration received by EFIH after the Secured Notes Issue Date in respect of Asset Sales of Collateral shall not exceed $400.0 million,

shall be deemed to be cash for purposes of this clause (A) and for no other purpose; and

    (B) any consideration received by EFIH from an Asset Sale of Collateral shall be concurrently pledged as Collateral for the benefit of the Holders of the Notes and holders of the other Secured Debt Obligations;provided that to the extent such consideration is received by EFIH in cash, it shall be held in an Asset Sale Cash Collateral Account pending the application of such cash consideration pursuant to this covenant.

In respect of Net Proceeds received by the Issuer or any Restricted Subsidiary from Asset Sales (other than an Asset Sale of Collateral or other Oncor-related Assets), within 450 days after the receipt of any Net Proceeds of any such 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;

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(c) Obligations under any Existing Notes with a maturity prior to October 15, 2019;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 such Existing Notes pursuant to this subclause (c) following the Secured Notes Issue Date shall not exceed 3.5% of Total Assets at such time; or

(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, to the extent that regulatory approval is necessary for an asset purchase 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 (other than Asset Sales of Collateral or other Oncor-related Assets) 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 and/or any of its Restricted Subsidiaries 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 and Additional Interest, if any, to the date fixed for the closing of such offer, in accordance with the procedures set forth in the Indenture. The Issuer and/or any of its Restricted Subsidiaries 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.

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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 and/or any of its Restricted Subsidiaries 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, the Notes and such Senior Indebtedness will 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 and/or any of its Restricted Subsidiaries may, at its/their option, make an Asset Sale Offer using proceeds from any Asset Sale (other than Asset Sales of Collateral or other Oncor-related Assets) 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.

In respect of Net Proceeds received by the Issuer or any Restricted Subsidiary (including EFIH) from Asset Sales of Collateral or other Oncor-related Assets, within 450 days after the receipt by the Issuer or any Restricted Subsidiary of any Net Proceeds of any such Asset Sale, the Issuer or such Restricted Subsidiary shall be required to deposit the Net Proceeds from such Asset Sale into an Asset Sale Cash Collateral Account that is subject to a perfected security interest for the benefit of the holders of Secured Lien Debt to be held solely for the purpose of repayment of principal, premium, if any, and interest and Additional Interest, if any, on, and/or to repay, prepay or repurchase, the Notes and other Parity Lien Obligations as described in the following clauses (1) and (2),

(1) to repay or prepay Parity Lien Debt (other than the Notes) (and, in the case of revolving loans and other similar obligations, permanently reduce the commitment thereunder) on a pro rata basis, but only up to an aggregate principal amount equal to such Net Proceeds to be used to repay Indebtedness pursuant to this clause (1) multiplied by a fraction, the numerator of which is the aggregate outstanding principal amount of such Parity Lien Debt and the denominator of which is the aggregate outstanding principal amount of all Parity Lien Debt (including the Notes), in each case based on amounts outstanding on the date of closing of such Asset Sale;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 by making an offer (in accordance with the procedures set forth below for a Collateral Asset Sale Offer) to all Holders to purchase their Notes at 100% of the principal amount thereof plus the amount of accrued and unpaid interest, if any; or

(2) to repay or repurchase any EFIH Notes or other Parity Lien Debt of EFIH.

Notwithstanding the preceding paragraph, in the event that regulatory approval is necessary for an Investment in any Oncor Subsidiary, 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 of Collateral or other Oncor-related Assets that are not invested or applied as provided and within the time period set forth in the first sentence of the preceding paragraph will be deemed to constitute “Collateral Excess Proceeds.” When the aggregate amount of Collateral Excess Proceeds exceeds $200.0 million, the Issuer and/or any of its Restricted Subsidiaries shall make an offer to all Holders of the Notes and, if required or permitted by the terms of any Parity Lien Debt, to the holders of such Parity Lien Debt (a “Collateral Asset Sale Offer”), to purchase the maximum aggregate principal amount of the Notes and such Parity Lien Debt that is a minimum of $2,000 or an integral multiple of $1,000 in excess thereof that may be purchased out of the Collateral Excess Proceeds at an offer price in cash in an amount equal to 100% of the principal amount thereof, plus accrued and unpaid interest and Additional Interest, if any, to the date fixed for the closing of such offer, in accordance with the procedures set forth in the Indenture. The Issuer and/or any of its Restricted Subsidiaries will commence a Collateral Asset Sale Offer with respect to Collateral Excess Proceeds within 10 Business Days after the date that Collateral Excess Proceeds exceed $200.0 million by mailing the notice required pursuant to the terms of the Indenture, with a copy to the Trustee.

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To the extent that the aggregate amount of Notes and such Parity Lien Debt tendered pursuant to a Collateral Asset Sale Offer is less than the Collateral Excess Proceeds, the Issuer and/or any of its Restricted Subsidiaries may use any remaining Collateral Excess Proceeds for general corporate purposes, subject to other covenants contained in the Indenture and the terms of such Parity Lien Debt. If the aggregate principal amount of Notes or the Parity Lien Debt surrendered by such holders thereof exceeds the amount of Collateral Excess Proceeds, the Notes and such Parity Lien Debt will be purchased on a pro rata basis based on the accreted value or principal amount of the Notes or such Parity Lien Debt tendered. Additionally, the Issuer and/or any of its Restricted Subsidiaries may, at its/their option, make a Collateral Asset Sale Offer using proceeds from any Asset Sale of Collateral or other Oncor-related Assets at any time after consummation of such Asset Sale;provided that such Collateral Asset Sale Offer shall be in an aggregate amount of not less than $25.0 million. Upon consummation of such Collateral Asset Sale Offer, any Net Proceeds not required to be used to purchase Notes shall not be deemed Collateral Excess Proceeds and the Issuer and its Restricted Subsidiaries may use any remaining Net Proceeds for general corporate purposes, subject to the other covenants contained in the Indenture.

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;provided,however, that any Net Proceeds that represents proceeds of Collateral or other Oncor-related Assets shall be deposited and held in an Asset Sale Cash Collateral Account that is subject to a perfected security interest for the benefit of the Holders of the Notes and the holders of the other Secured Debt Obligations pending final application thereof in accordance with this covenant. For the avoidance of doubt, final application of Net Proceeds that represent proceeds of Collateral or other Oncor-related Assets includes, without limitation, the consummation of a Collateral Asset Sale Offer.

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 or a Collateral 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.

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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

(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 apro 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 apro 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):

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(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 11, 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 11, 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 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 (other than Restricted Investments in any Oncor Subsidiary or Successor Oncor Business) 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

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(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 any Successor Oncor Business) or a distribution or dividend from an Unrestricted Subsidiary after the Closing Date (other than distributions or dividends from the Oncor Subsidiaries or any Successor Oncor Business, except to the extent such distributions or dividends were received prior to the Secured Notes Issue Date and exceeded 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 did not exceed such aggregate amount of Investments then 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);plus

(e) in the case of the redesignation of an Unrestricted Subsidiary (other than the Oncor Subsidiaries or any Successor Oncor Business) 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.

As of September 30, 2010, the Issuer would have had approximately $1.9 billion available for Restricted Payments under clause (3) above.

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:

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(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 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 entity 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);

andprovided, 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”;

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(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;

(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 or any Successor Oncor Business, $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 membership interests 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 in an aggregate amount equal to the amount of 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”;

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(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 “— 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, Asset Sale Offer or Collateral Asset Sale Offer, as applicable, have been repurchased, redeemed or acquired for value;

(15) the declaration and payment of dividends by the Issuer to, or the making of loans to, any direct or indirect parent company 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;

(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; and

(e) fees and expenses other than to Affiliates of the Issuer related to any unsuccessful equity or debt offering of such parent entity; or

(16) the spin-off by the Issuer of the Equity Interests of EFIH in a Permitted Asset Transfer made in accordance with the covenant described under “— Restrictions on Permitted Asset Transfers”;

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.

As of the date of this prospectus, all of the Issuer’s Subsidiaries (other than the Oncor Subsidiaries, Comanche Peak Nuclear Power Company, Nuclear Energy Future Holdings LLC and Nuclear Energy Future Holdings II LLC) are Restricted Subsidiaries. The Issuer will not permit any Unrestricted Subsidiary to become a Restricted Subsidiary except pursuant to the penultimate paragraph 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.

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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 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 Stock or Preferred Stock is issued would have been at least 2.00 to 1.00, in each case determined on apro forma basis (including apro 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 (w) by the Issuer or any Guarantor of Indebtedness represented by the Notes issued on the Issue Date (including any Guarantees thereof) and any Exchange Notes (including any guarantees thereof), (x) by the Issuer of Indebtedness represented by the 9.75% Notes and any additional 9.75% Notes (including any guarantees thereof) and by EFIH of Indebtedness represented by the EFIH Notes and any additional EFIH Notes, (y) by the Issuer of any Additional Notes to be issued after the Issue Date (including any guarantees thereof) and (z) by the Issuer or any Guarantor of any other Indebtedness;provided that the aggregate principal amount of Indebtedness incurred under this clause (2), together with refinancings thereof, shall not exceed $4.0 billion; andprovided,further that the aggregate amount of Indebtedness that may be incurred under this clause (2) shall be reduced by an amount equal to the amount of Parity Lien Debt repaid using the Net Proceeds from Asset Sales of Collateral or other Oncor-related Assets in accordance with the covenant described under “ — Repurchase at the Option of Holders — Asset Sales”;

(3) Indebtedness of the Issuer and its Restricted Subsidiaries in existence on the Issue Date (other than Indebtedness described in clauses (1) and (2)), including the Existing Notes (including any PIK interest which may be paid with respect thereto and guarantees thereof);

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(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 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;

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(12)(a) Indebtedness or Disqualified Stock of the Issuer and Indebtedness, Disqualified Stock or Preferred Stock of 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 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,

(b) to the extent such Refinancing Indebtedness refinances (i) Indebtedness subordinated orpari passu to the Notes or any Guarantee thereof, such Refinancing Indebtedness is subordinated orpari 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; 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

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(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 its 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 “— Limitation on Restricted Payments.”

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 Issue Date will be treated as incurred on the Issue 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.

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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 that is a Restricted Subsidiary 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 that is a Restricted Subsidiary, 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 any related Guarantees are secured by a Lien on such property, assets or proceeds that is senior in priority to such Liens; or

(2) in all other cases, the Notes or any 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 Indebtedness permitted to be incurred pursuant to clause (2) of the second paragraph under “— Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;provided that the Notes or any related Guarantee are secured on at least an equal and ratable basis as such Indebtedness, (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 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 givingpro 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 obligation to so secure the Notes.

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Notwithstanding the foregoing, the Issuer will not, and will not permit EFIH to, directly or indirectly, create, incur, assume or suffer to exist any Lien on the Collateral (other than a Permitted Lien described under clause (3) of the definition of “Permitted Liens”), or any income or profits therefrom, or assign or convey any right to receive income therefrom except:

(1) Liens on the Collateral securing up to $4.0 billion in aggregate principal amount of Parity Lien Debt (including the Notes, Additional Notes, Exchange Notes and the 9.75% Notes, any additional 9.75% Notes, the EFIH Notes and any additional EFIH Notes and any guarantees of any of the foregoing and/or other Indebtedness incurred pursuant to the covenant described under “— Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”);provided that such amount shall be reduced by an amount equal to the amount of Parity Lien Debt repaid using the Net Proceeds from Asset Sales of Collateral or other Oncor-related Assets in accordance with the covenant described under “— Repurchase at the Option of Holders — Asset Sales”; and

(2) Junior Liens on the Collateral securing Junior Lien Debt permitted to be incurred pursuant to the covenant described under “— Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock.”

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, wind-up 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, the Indenture and the Security Documents, to the extent the Issuer is a party thereto, pursuant to a supplemental indenture or other document or instrument in form reasonably satisfactory to the Trustee and (ii) the Registration Rights Agreement;

(3) immediately after such transaction, no Default exists;

(4) immediately after givingpro forma effect to such transaction and any related financing transactions (including, without limitation, any transaction the proceeds of which are applied to reduce the Indebtedness of the Successor Company or the Issuer, as the case may be), 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 (1)(b) of the second succeeding paragraph shall apply, shall have by a supplemental indenture confirmed that its Guarantee and any Security Documents to which it is a party 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, wind-up, merger or transfer and such supplemental indenture, if any, comply with the Indenture and, if a supplemental indenture is required in connection with such transaction, such supplemental indenture shall comply with the applicable provisions of the Indenture;

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provided , that for the purposes of this covenant only, neither (A) the first to occur of a Permitted Asset Transfer or a TCEH Transfer (excluding a Permitted Asset Transfer consisting of a merger of EFIH with and into the Issuer for the purpose of determining the first to occur of a Permitted Asset Transfer or a TCEH Transfer) nor (B) a transaction meeting the requirements of the proviso to clause (3) under the definition of “Change of Control” will be deemed to be a sale, assignment, transfer, conveyance or other disposition of all or substantially all of the properties or assets of the Issuer and its Subsidiaries under the Indenture. For the avoidance of doubt, (1) the Issuer may therefore consummate the first to occur of a Permitted Asset Transfer made in accordance with the covenant described under “— Certain Covenants — Restrictions on Permitted Asset Transfers” and a TCEH Transfer made in accordance with the covenant described under “— Restrictions on TCEH Transfer,” in either case, without complying with this “Merger, Consolidation or Sale of All or Substantially All Assets” covenant (excluding a Permitted Asset Transfer consisting of a merger of EFIH with and into the Issuer for the purpose of determining the first to occur of a Permitted Asset Transfer or a TCEH Transfer), (2) the Issuer or any of its Restricted Subsidiaries may consummate a transaction meeting the requirements of the proviso to clause (3) under the definition of “Change of Control” without complying with this “Merger, Consolidation or Sale of All or Substantially All Assets” covenant and (3) the determination in the preceding proviso shall not affect the determination of what constitutes all or substantially all the assets of the Issuer and its Subsidiaries under any other agreement to which the Issuer is a party.

The Successor Company will succeed to, and be substituted for, the Issuer under the Indenture and the Notes. Notwithstanding clauses (3) and (4) of the first paragraph of this “Merger, Consolidation or Sale of All or Substantially All Assets” covenant,

(1) any Restricted Subsidiary (other than EFIH) 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 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.

Notwithstanding the foregoing, EFIH may merge with and into the Issuer in a Permitted Asset Transfer in accordance with the covenant described under “— Restrictions on Permitted Asset Transfers.”

Subject to certain limitations described in the Indenture governing release of a Guarantee upon the sale, disposition or transfer of a Guarantor, and except in the case of a Permitted Asset Transfer made in accordance with “— Restrictions on Permitted Asset Transfers,” 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, wind-up 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 and any Security Documents to which such Guarantor is a party 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

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(d) the Issuer shall have delivered to the Trustee an Officer’s Certificate and an Opinion of Counsel, each stating that such consolidation, wind-up, 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, (i) any Guarantor may 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, and any Guarantor (other than EFIH) may (A) merge into or transfer all or part of its properties and assets to another Guarantor or the Issuer or (B) 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 and (ii) EFIH may merge with and into the Issuer in a Permitted Asset Transfer in accordance with the covenant described under “— Restrictions on Permitted Asset Transfers.”

Restrictions on Permitted Asset Transfers

The Issuer will not, and will not permit any of its Restricted Subsidiaries to, consummate a Permitted Asset Transfer unless:

(1) in the case of a Permitted Asset Transfer described in clause (2) of the definition of “Permitted Asset Transfer” or a Permitted Asset Transfer described in clause (1) of the definition of “Permitted Asset Transfer” by way of merger, wind-up or consolidation, the Person to which such sale, assignment, transfer, conveyance or other disposition of all of the Equity Interests of, and other Investments in, any Oncor Subsidiary and all other Collateral held by EFIH has been made is a corporation organized or existing under the laws of the United States, any state of the United States, the District of Columbia or any territory thereof (such Person being herein called the “Successor EFIH Company”);provided that the Successor EFIH Company may not be an Oncor Subsidiary;

(2) the Successor EFIH Company or, in the case of a Permitted Asset Transfer described in clause (1) of the definition of “Permitted Asset Transfer,” EFIH and, to the extent the Successor EFIH Company is not a corporation, a Subsidiary of EFIH or the Successor EFIH Company, as the case may be, that is a co-obligor and a corporation organized or existing under the laws of the United States, any state of the United States, the District of Columbia or any territory thereof, has assumed all the obligations of the Issuer and EFIH under (i) the Notes and the Indenture (except in the case of a Permitted Asset Transfer consisting of a merger of EFIH with and into the Issuer, pursuant to a supplemental indenture, a form of which will be contained in an annex to the Indenture (the “Permitted Transfer Supplemental Indenture”)), the Security Documents to which the Issuer or EFIH is a party pursuant to agreements, in each case, reasonably satisfactory to the Trustee and the Collateral Trustee and (ii) the Registration Rights Agreement;

(3) immediately after such transaction no Default exists;

(4) immediately after givingpro forma effect to such transaction and any related financing transactions (including, without limitation, any transaction the proceeds of which are applied to reduce the Indebtedness of the Successor EFIH Company or EFIH, as the case may be) as if the same had occurred at the beginning of the applicable four-quarter period, either:

(a) the Successor EFIH Company, or EFIH, as the case may be, would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the fixed charge coverage ratio test set forth in the Permitted Transfer Supplemental Indenture; or

(b) the fixed charge coverage ratio (as defined in the Permitted Transfer Supplemental Indenture) for the Successor EFIH Company and its Restricted Subsidiaries or EFIH and its Restricted Subsidiaries, as the case may be, would be greater than such fixed charge coverage ratio for the Issuer and its Restricted Subsidiaries immediately prior to such transaction;

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(5) except in the case of a Permitted Asset Transfer consisting of a merger of EFIH with and into the Issuer, the rating on the Notes shall not have been downgraded by two or more of the Rating Agencies (or, if the Notes are rated by only one Rating Agency at the time of the first notice of such Permitted Asset Transfer, such Rating Agency) during the period commencing 30 days prior to the first public notice of the occurrence of a Permitted Asset Transfer or the intention of the Issuer or any Subsidiary thereof to effect a Permitted Asset Transfer and ending on the date 60 days after such public notice relative to the rating at the start of such period; and

(6) the Issuer shall have delivered to the Trustee an Opinion of Counsel confirming that, subject to customary assumptions, exclusions and qualifications, the existing Security Documents, or to the extent that a Permitted Asset Transfer pursuant to clause (1) of the definition of “Permitted Asset Transfer” by way of merger, wind-up or consolidation or pursuant to clause (2) of the definition of “Permitted Asset Transfer” is being consummated, any new or amended Security Documents to be entered into by the Successor EFIH Company, are enforceable obligations of EFIH or the Successor EFIH Company, as the case may be, create a legally valid and enforceable security interest in the Collateral in favor of the Collateral Trustee for the benefit of the Holders of the Notes and the other Secured Debt Obligations, and that the security interests in the Collateral created by the Security Documents have been perfected.

The Permitted Transfer Supplemental Indenture will amend the definitions, covenants, events of default and other terms of the Indenture. The amended terms will be substantially similar to the terms of the EFIH Notes. For the avoidance of doubt, calculations under the Permitted Transfer Supplemental Indenture from and after the Permitted Asset Transfer will be made in accordance with the calculations relating to the EFIH Notes but, in respect of actions taken from and after the Permitted Asset Transfer, treating the Notes as if they had been issued by EFIH on the Secured Notes Issue Date.

In the case of a Permitted Asset Transfer described in clause (2) of the definition of “Permitted Asset Transfer” or a Permitted Asset Transfer described in clause (1) of the definition of “Permitted Asset Transfer” by way of merger, wind-up or consolidation, the Guarantee by EFIH will be released upon the consummation of such Permitted Asset Transfer in accordance with this “Restrictions on Permitted Asset Transfers” covenant. The successor entity formed by any merger of EFIH with and into the Issuer that is permitted by the Indenture shall not be permitted to effect a Permitted Asset Transfer described in clause (1) of the definition of Permitted Asset Transfer.

The provisions of this “Restrictions on Permitted Asset Transfers” covenant will not apply to a sale, assignment, transfer, conveyance or other disposition of assets between or among the Oncor Subsidiaries.

Restrictions on TCEH Transfers

The Issuer will not, and will not permit any of its Restricted Subsidiaries to, consummate a TCEH Transfer unless:

(1) the Issuer and the Trustee enter into a supplemental indenture, a form of which will be contained in an annex to the Indenture (the “TCEH Transfer Supplemental Indenture”), that will become operative at the time of consummation of such TCEH Transfer;

(2) immediately after such transaction no Default exists;

(3) immediately after givingpro forma effect to such transaction and any related financing transactions (including, without limitation, any transaction the proceeds of which are applied to reduce the Indebtedness of the Issuer) as if the same had occurred at the beginning of the applicable four-quarter period, either:

(a) the Issuer would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the fixed charge coverage ratio test set forth in the TCEH Transfer Supplemental Indenture; or

(b) the fixed charge coverage ratio (as defined in the TCEH Transfer Supplemental Indenture) for the Issuer and its Restricted Subsidiaries would be greater than such fixed charge coverage ratio for the Issuer and its Restricted Subsidiaries immediately prior to such transaction; and

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(4) the rating on the Notes shall not have been downgraded by two or more of the Rating Agencies (or, if the Notes are rated by only one Rating Agencies at the time of the first notice of such TCEH Transfer, such Rating Agency) during the period commencing 30 days prior to the first public notice of the occurrence of a TCEH Transfer or the intention of the Issuer or any Subsidiary thereof to effect a TCEH Transfer and ending on the date 60 days after such public notice relative to the rating at the start of such period.

The TCEH Transfer Supplemental Indenture will amend the definitions, covenants, events of default and other terms of the Indenture. The amended terms will be substantially similar to the terms of the EFIH Notes, although Energy Future Holdings Corp. will continue to be the Issuer under the TCEH Transfer Supplemental Indenture.

Restrictions on Certain Investments in Oncor Subsidiaries and the Collateral

The Issuer will not, and will not permit any Restricted Subsidiary (other than EFIH) to, hold any Equity Interests in, or Indebtedness of, or other Investments in, any of the Oncor Subsidiaries or any Successor Oncor Business or any other Collateral, except the Issuer may hold such Equity Interests, Indebtedness and other Investments following a merger of EFIH with and into the Issuer which is a Permitted Asset Transfer made in accordance with the provisions described under “— Restrictions on Permitted Asset Transfers.”

The Issuer will not permit any Unrestricted Subsidiary to hold any Equity Interests in, or Indebtedness of, or other Investments in, EFIH, and will not permit any Unrestricted Subsidiary to hold any Equity Interests in, or Indebtedness of, or other Investments in, any of the Oncor Subsidiaries or any Successor Oncor Business;provided that an Oncor Subsidiary may hold Equity Interests in, or Indebtedness of, or other Investments in, another Oncor Subsidiary and a Successor Oncor Business may hold Equity Interests in, Indebtedness of, or other Investments in, another Successor Oncor Business.

The Issuer will not permit any of its Unrestricted Subsidiaries to accept any Investment from any Oncor Subsidiary or any Successor Oncor Business;provided that an Oncor Subsidiary may accept an Investment from another Oncor Subsidiary and a Successor Oncor Business may accept an Investment from another Successor Oncor Business.

EFIH will not sell, assign, transfer, convey or otherwise dispose of any Collateral, including any consideration (other than cash and Cash Equivalents) received by EFIH in an Asset Sale, including in respect of a Permitted Asset Swap of Collateral, except in connection with a Permitted Asset Transfer that satisfies the requirements of the covenant described under “— Restrictions on Permitted Asset Transfers” or pursuant to an Asset Sale that complies with the provisions of the covenant described under “— Repurchase at the Option of Holders — Asset Sales” pertaining to an Asset Sale of Collateral.

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

(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:

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(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” or to any Permitted Asset Transfer made in accordance with the covenant described under “— Restrictions on Permitted Asset Transfers” to the extent agreements with respect to which contain reasonable and customary provisions (as determined by the Issuer in good faith);

(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 Issue 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 Issue Date);

(4) the payment of reasonable and customary fees paid to, and indemnities provided for the benefit of, officers, directors, employees or consultants of the 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 Issue 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 Issue 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 Issue 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 Issue 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;

(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;

(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;

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(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 Issue Date, including pursuant to the TCEH Senior Secured Facilities and the related documentation and the Existing Notes Indentures and the related documentation;

     (b)(i) the Indenture, the Notes and the Security Documents and (ii) the EFIH Notes and related documentation (including the related security documents) 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;

     (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;

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     (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 Issue 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 permitted to be incurred subsequent to the Issue 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 Indenture (in the case of Indebtedness of TCEH and its restricted Subsidiaries) or the EFIH Indenture (in the case of Indebtedness of EFIH and its restricted Subsidiaries), in the case of either of such Indentures only, as in effect on the Issue 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 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 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.

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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;

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.

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In the event that any direct or indirect parent company of the Issuer becomes a Guarantor of the Notes, the Indenture will permit 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 or Additional Interest, if any, 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, the Notes or the Security Documents relating to 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 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);

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(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; or

(8) with respect to Collateral having a fair market value in excess of $250.0 million in the aggregate, any security interest and Lien purported to be created by any Security Document with respect to the Collateral (a) ceases to be in full force and effect, (b) ceases to give the Collateral Trustee, for the benefit of the holders of the Notes, the Liens, rights, powers and privileges purported to be created and granted thereby (including a perfected first-priority security interest in and Lien on, all of the Collateral thereunder) in favor of the Collateral Trustee, or (c) is asserted by EFIH not to be, a valid, perfected, first priority (except as otherwise expressly provided in the Indenture or the Collateral Trust Agreement) security interest in or Lien on the Collateral covered thereby.

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.

Holders of the Notes may not enforce the Indenture, the Notes, the Security Documents or the Collateral Trust Agreement except as provided in such documents. 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

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(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 indemnity or security reasonably satisfactory to it 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;

(3) Holders of the Notes have offered the Trustee security or indemnity reasonably satisfactory to it 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 past, present or future 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, the Indenture, the Registration Rights Agreement or any Security Document 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;

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(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, 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 the Bankruptcy 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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The Collateral will be released from the Lien securing the Notes, as provided under “— Security for the Notes — Release of Security Interests,” upon a Legal Defeasance or Covenant Defeasance in accordance with the provisions described in this “Legal Defeasance and Covenant Defeasance” section.

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 and unpaid 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.

The Collateral will be released from the Lien securing the Notes, as provided under “— Security for the Notes — Release of Security Interests,” upon a discharge of the Indenture in accordance with the provisions described in this “Satisfaction and Discharge” section.

Amendment, Supplement and Waiver

Except as provided in the next two succeeding paragraphs, the Indenture, the Guarantees, the Notes and the Security Documents relating to 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 or the Security Documents relating to the Notes 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).

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:

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(1) reduce the principal amount of such Notes whose Holders must consent to an amendment, supplement or waiver;

(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 (for the avoidance of doubt, the provisions described under “— Repurchase at the Option of Holders” are not redemptions of Notes);

(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 provisions of the Indenture or 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.

In addition, without the consent of at least a majority in aggregate principal amount of the Notes then outstanding, an amendment, supplement or waiver may not modify any Security Document relating to the Notes or the provisions of the Indenture dealing with the Security Documents or application of trust moneys in any manner materially adverse to the Holders other than in accordance with the Indenture and the Security Documents. Without the consent of at least 66²/3% in aggregate principal amount of the Notes then outstanding, no amendment, supplement or waiver may modify the Security Documents to release all or substantially all of the Collateral. Without the consent of at least a majority in aggregate principal amount of the Notes then outstanding, no amendment, supplement or waiver may modify the Security Documents to release less than all or substantially all of the Collateral.

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, any Guarantee, the Notes or any Security Document without the consent of any Holder to;

(1) cure any ambiguity, omission, mistake, defect or inconsistency;

(2) provide for uncertificated Notes of such series in addition to or in place of certificated Notes;

(3) comply with the covenant relating to mergers, consolidations and sales of assets;

(4) provide for the assumption of the Issuer’s or any Guarantor’s obligations to the Holders;

(5) 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) add covenants for the benefit of the Holders or to surrender any right or power conferred upon the Issuer or any Guarantor;

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(7) comply with requirements of the SEC in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act;

(8) evidence and provide for the acceptance and appointment under the Indenture of a successor Trustee thereunder pursuant to the requirements thereof;

(9) provide for the issuance of Additional Notes;

(10) 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;

(11) add a Guarantor under the Indenture;

(12) conform the text of the Indenture, the Guarantees, the Notes or any Security Document to any provision of this “Description of the Notes” to the extent that such provision in this “Description of the Notes” was intended to be a verbatim recitation of a provision of the Indenture, the Guarantees, the Notes or any Security Document;

(13) 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 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;

(14) 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;

(15) amend the Indenture in the manner set forth in the Permitted Transfer Supplemental Indenture to be entered into in connection with the consummation of a Permitted Asset Transfer in the manner set forth under “— Certain Covenants — Restrictions on Permitted Asset Transfers” or in the TCEH Transfer Supplemental Indenture to be entered into in connection with the consummation of a TCEH Transfer in the manner set forth under “— Certain Covenants — Restrictions on TCEH Transfers”; or

(16) provide for the accession or succession of any parties to the Security Documents (and other amendments that are administrative or ministerial in nature) in connection with an amendment, renewal, extension, substitution, refinancing, restructuring, replacement, supplementing or other modification from time to time of any agreement or action that is not prohibited by the Indenture, including to add any additional secured parties to the extent not prohibited by the Indenture.

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.

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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 will be 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.

“9.75% Notes” means the 9.75% Senior Secured Notes due 2019 issued by the Issuer under the 9.75% Notes Indenture, including the guarantees thereof.

“9.75% Notes Indenture” means the Indenture, dated as of November 16, 2009, under which the 9.75% Notes were issued.

“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.

“Act of Required Debtholders” means, as to any matter at any time:

(1) prior to the Discharge of Parity Lien Obligations, a direction in writing delivered to the Collateral Trustee by or with the written consent of the holders of a majority of the sum of:

(a) the aggregate outstanding principal amount of Parity Lien Debt (including outstanding letters of credit whether or not then available or drawn); and

(b) the aggregate unfunded commitments to extend credit which, when funded, would constitute Parity Lien Debt; and

(2) at any time after the Discharge of Parity Lien Obligations, a direction in writing delivered to the Collateral Trustee by or with the written consent of the holders of Junior Lien Debt representing the Required Junior Lien Debtholders.

For purposes of this definition, (a) Secured Lien Debt registered in the name of, or beneficially owned by, the Issuer or any Affiliate of the Issuer will be deemed not to be outstanding, and (b) votes will be determined in accordance with the provisions described under “— Security for the Notes — Voting.”

“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.

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“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) the excess, if any, of (a) the present value at such Redemption Date of (i) the redemption price of such Note at January 15, 2015 (such redemption price being set forth in the table appearing under “— Optional Redemption”), plus (ii) all required interest payments due on such Note through January 15, 2015 (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 Note.

“Asset Sale” means:

(1) the sale, conveyance, transfer or other disposition (each referred to in this definition as a “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 (including the disposition of outstanding Equity Interests of an Unrestricted Subsidiary owned directly by the Issuer or any of its Restricted Subsidiaries) and, solely to the extent cash or Cash Equivalents are received therefrom by any Oncor Subsidiary or any Successor Oncor Business and are thereafter dividended, distributed or otherwise paid to the Issuer or any of its Restricted Subsidiaries: (i) the primary issuance of new Equity Interests by any Oncor Subsidiary or any Successor Oncor Business, (ii) the disposition of outstanding Equity Interests of an Oncor Subsidiary or a Successor Oncor Business owned directly by another Oncor Subsidiary or by another Successor Oncor Business and (iii) the disposition of assets owned directly or indirectly by any Oncor Subsidiary or any Successor Oncor Business. For the avoidance of doubt, with respect to Unrestricted Subsidiaries other than Oncor Subsidiaries or Successor Oncor Businesses, the following shall not be deemed to be “Asset Sales”: (i) the primary issuance of new Equity Interests by an Unrestricted Subsidiary and (ii) sales or transfers of assets owned directly by Unrestricted Subsidiaries; 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)(1) the disposition of all or substantially all of the assets of the Issuer in a manner permitted by the covenant described under “— Certain Covenants — Merger, Consolidation or Sale of All or Substantially All Assets” (other than a disposition excluded from such covenant by the proviso at the end of the first paragraph of such covenant) or any disposition that constitutes a Change of Control pursuant to the Indenture or (2) any Permitted Asset Transfer made in accordance with the covenant described under “— Restrictions on Permitted Asset Transfers”;

     (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”;

     (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;

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     (e) any disposition of property or assets or issuance of securities by a Restricted Subsidiary to the Issuer or by the Issuer or a Restricted Subsidiary to another Restricted Subsidiary;provided however to the extent such transfer involves Collateral or any part thereof, the transferee shall execute a joinder agreement to the Security Documents and the Collateral Trust Agreement or enter into a substantially similar collateral trust or intercreditor agreement immediately upon consummation of such transaction in accordance with the requirements of the Security Documents to pledge such transferred Collateral for the benefit of the Holders of the Notes;

     (f) except in the case of a disposition of Collateral, 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 disposition of Equity Interests in an Unrestricted Subsidiary (other than an Oncor Subsidiary or a Successor Oncor Business) and (ii) any sale, conveyance, transfer or other disposition of Equity Interests in, or assets of, any of the Oncor Subsidiaries or a Successor Oncor Business (other than the Collateral) to the extent no cash or Cash Equivalents are received in connection with such sale, conveyance, transfer or other disposition or to the extent any cash or Cash Equivalents received in connection with such sale, conveyance, transfer or other disposition are not dividended, distributed or otherwise paid to the Issuer or any of its Restricted Subsidiaries;

     (i) foreclosures on assets not constituting Collateral;

     (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 Issue Date, including Sale and Lease-Back Transactions and asset securitizations permitted by the Indenture;

     (l)[Intentionally omitted];

     (m) except in the case of a disposition of Collateral, 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 covenant described 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 covenant described under “Repurchase at the Option of Holders — Asset Sales”;

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     (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 the Issuer not to be necessary for use for 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 the Issuer 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 covenant described 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 covenant described under “— Repurchase at the Option of Holders — Asset Sales.”

“Asset Sale Cash Collateral Account” means a segregated account pledged under the Security Documents that is (i) subject to a perfected security interest for the benefit of the holders of Secured Lien Debt, (ii) under the sole control of the Collateral Trustee and (iii) free from all other Liens (other than Liens permitted to be placed on the Collateral pursuant to the second paragraph of the covenant described under “— Certain Covenants — Liens”).

“Asset Sale Offer” has the meaning set forth in the covenant described 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 Issue 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.

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“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.

“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, other than (A) the first to occur of a Permitted Asset Transfer made in accordance with the covenant described under “— Certain Covenants — Restrictions on Permitted Asset Transfers” and a TCEH Transfer made in accordance with the covenant described under “— Certain Covenants — Restrictions on TCEH Transfer” (excluding a Permitted Asset Transfer consisting of a merger of EFIH with and into the Issuer for the purpose of determining the first to occur of a Permitted Asset Transfer or a TCEH Transfer), (B) a transaction meeting the requirements of the proviso to clause (3) of this definition of “Change of Control” and (C) any foreclosure on the Collateral;

(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; or

(3) the sale, transfer, conveyance or other disposition, in one or a series of related transactions, of all or substantially all of the assets of EFIH and its Subsidiaries, taken as a whole, or all or substantially all of the Collateral or Oncor-related Assets, other than a Permitted Asset Transfer made in accordance with the covenant described under “— Certain Covenants — Restrictions on Permitted Asset Transfers”;provided, however, that a transaction that would otherwise constitute a Change of Control pursuant to this clause (3) shall not constitute a Change of Control if:

(a) the consideration received in respect of such transaction (i) is received by EFIH or an Oncor Subsidiary or Successor Oncor Business, as the case may be, (ii) consists of Capital Stock of a Person in a Similar Oncor Business that (A) would become a Subsidiary of EFIH or such Oncor Subsidiary or Successor Oncor Business or (B) is a joint venture in which EFIH or such Oncor Subsidiary or Successor Oncor Business would have a significant equity interest (as determined by the Issuer in good faith), (iii) is at least equal to the fair market value (as determined by the Issuer in good faith) of the assets sold, transferred, conveyed or otherwise disposed of and (iv) if received by EFIH, shall be concurrently pledged as Collateral for the benefit of the Holders of the Notes and the holders of the other Secured Debt Obligations;

(b) immediately after such transaction no Default exists;

(c) immediately after givingpro forma effect to such transaction and any related financing transactions (including, without limitation, any transaction the proceeds of which are applied to reduce the Indebtedness of the Issuer or EFIH) as if the same had occurred at the beginning of the applicable four-quarter period, either:

(i) the Issuer would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in clause (i) of the first paragraph of the covenant described under “— Certain Covenants — Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”; or

(ii) such Fixed Charge Coverage Ratio for the Issuer and its Restricted Subsidiaries would be greater than such Fixed Charge Coverage Ratio for the Issuer and its Restricted Subsidiaries immediately prior to such transaction; and

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(d) the rating on the Notes shall not have been downgraded by two or more of the Rating Agencies (or, if the Notes are rated by only one Rating Agency at the time of the first notice of such transaction, such Rating Agency) during the period commencing 30 days prior to the first public notice of the occurrence of such transaction or the intention of the Issuer or any Subsidiary thereof to effect such transaction and ending on the date 60 after such public notice relative to the rating at the start of such period.

“Class”means (1) in the case of Parity Lien Debt, every Series of Parity Lien Debt, taken together, and (2) in the case of Junior Lien Debt, every Series of Junior Lien Debt, taken together.

“Closing Date” means October 10, 2007.

“Code” means the Internal Revenue Code of 1986, as amended, or any successor thereto.

“Collateral” means all assets or property, now owned or hereafter acquired by EFIH, to the extent such assets or property are pledged or assigned or purported to be pledged or assigned, or are required to be pledged or assigned under the Security Documents to the Collateral Trustee, together with the proceeds thereof.

“Collateral Asset Sale Offer” has the meaning set forth under “— Repurchase at the Option of Holders — Asset Sales.”

“Collateral Excess Proceeds” has the meaning set forth under “— Repurchase at the Option of Holders — Asset Sales.”

“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.

“Collateral Trustee” means The Bank of New York Mellon Trust Company, N.A., in its capacity as Collateral Trustee under the Collateral Trust Agreement, together with its successors in such capacity.

“Collateral Trustee’s Liens” means a Lien granted to the Collateral Trustee as security for Secured Debt Obligations.

“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” imposed in connection with failure to register any 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

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(2) interest on Indebtedness of another Person that is guaranteed by EFIH solely to the extent such interest is actually paid by EFIH under such guarantee;plus

(3) consolidated capitalized interest of such Person and its Restricted Subsidiaries for such period, whether paid or accrued;less

(4) interest income of such Person and its Restricted Subsidiaries for such period.

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 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) not a Subsidiary, (b) an Unrestricted Subsidiary or (c) 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, other than dividends, distributions or other payments from the Oncor Subsidiaries or any Successor Oncor Business (i) from the proceeds of sales of Oncor-related Assets made after the Secured Notes Issue Date and (ii) consisting of Oncor-related Assets made after the Secured Notes Issue Date;

(6) solely for the purpose of determining the amount available for Restricted Payments under clause (3)(a) of the first paragraph under “— 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.

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“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 the date on which such event for which such calculation is being made shall occur, in each case with suchpro forma adjustments to Consolidated Secured Indebtedness and EBITDA as are appropriate and consistent with thepro 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)).

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“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, 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.”

“Discharge of Parity Lien Obligations” means the occurrence of all of the following:

(1) termination or expiration of all commitments to extend credit that would constitute Parity Lien Debt;

(2) payment in full in cash of the principal of, and interest and premium, if any, on, all Parity Lien Debt (other than any undrawn letters of credit);

(3) discharge or cash collateralization (at the lower of (A) 105% of the aggregate undrawn amount and (B) the percentage of the aggregate undrawn amount required for release of liens under the terms of the applicable Parity Lien Document) of all outstanding letters of credit constituting Parity Lien Debt; and

(4) payment in full in cash of all other Parity Lien Obligations that are outstanding and unpaid at the time the Parity Lien Debt is paid in full in cash (other than any obligations for taxes, costs, indemnifications, reimbursements, damages and other liabilities in respect of which no claim or demand for payment has been made at such time).

“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.

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“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 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 exchange offers pursuant to which the 9.75% Notes and EFIH Notes were issued, the offering of any Additional Notes or Exchange Notes or any additional 9.75% Notes or EFIH Notes, the offerings of the Existing 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

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(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 apro 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 topro forma adjustments made pursuant to the second paragraph of the definition of “Fixed Charge Coverage Ratio”);plus

(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.

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“EFH Senior Interim Facility” means the interim loan agreement, dated as of the Closing Date by and among the Issuer, as borrower, EFCH and EFIH, 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.

“EFIH Indenture” means the Indenture, dated as of November 16, 2009, under which the EFIH Notes were issued.

“EFIH Notes” means the 9.75% Senior Secured Notes due 2019 issued by EFIH and EFIH Finance Inc. under the EFIH Indenture, including any guarantees 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.

“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 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.

“equally and ratably” means, in reference to sharing of Liens or proceeds thereof as between the holders of Secured Debt Obligations within the same Class after the repayment of amounts payable to the Collateral Trustee under the Collateral Trust Agreement and the Parity Lien Representatives (and in the case of Junior Lien Obligations, Junior Lien Representatives) in accordance with the applicable Secured Debt Document that such Liens or proceeds:

(1) will be allocated and distributed first to the Secured Debt Representative for each outstanding Series of Secured Lien Debt within that Class, for the account of the holders of such Series of Secured Lien Debt, ratably in proportion to the principal of, and interest and premium (if any) and reimbursement obligations (contingent or otherwise) with respect to letters of credit, if any, outstanding (whether or not drawings have been made under such letters of credit) forming part of, and Hedging Obligations to the extent constituting Secured Lien Debt pursuant to the terms of, each outstanding Series of Secured Lien Debt within that Class when the allocation or distribution is made; and thereafter

(2) will be allocated and distributed (if any remain after payment in full of all of the principal of, and interest and premium (if any) and reimbursement obligations (contingent or otherwise) with respect to letters of credit, if any, outstanding (whether or not drawings have been made on such letters of credit) forming part of, and Hedging Obligations to the extent constituting Secured Indebtedness pursuant to the terms of, each outstanding Series of Secured Lien Debt within that Class) to the Secured Debt Representative for each outstanding Series of Secured Lien Debt within that Class, for the account of the holders of any remaining Secured Debt Obligations within that Class, ratably in proportion to the aggregate unpaid amount of such remaining Secured Debt Obligations within that Class due and demanded (with written notice to the applicable Secured Debt Representative and the Collateral Trustee) prior to the date such distribution is made.

“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.

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“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, Inc. or any entity approved to perform the functions of an independent system operator within the power region that includes approximately 80% of the electric transmission within the State 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;

• Energy Future Holdings Corp. 6.55% Fixed Senior Notes Series R due 2034;

• Energy Future Holdings Corp. 10.875% Senior Notes due 2017;

• Energy Future Holdings Corp. 11.250%/12.000% Senior Toggle Notes due 2017;

• 9.75% Notes;

• EFIH Notes;

• EFCH Floating Rate Junior Subordinated Debentures, Series D due 2037;

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• EFCH 8.175% Fixed Junior Subordinated Debentures, Series E due 2037;

• EFCH 9.580% Fixed Notes due in semi-annual installments to 2019;

• EFCH 8.254% Fixed Notes due in quarterly installments to 2021;

• TCEH Notes;

• TCEH 7.000% Fixed Senior Notes due 2013;

• TCEH 7.460% Fixed Secured Facility Bonds with amortizing payments to 2015;

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;

• 8.250% Fixed Series 2001A due October 1, 2030;

• 5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011;

• 8.250% Fixed Series 2001D-1 due May 1, 2033.

• Floating Series 2001D-2 due May 1, 2033;

• Floating Taxable Series 2001I due December 1, 2036;

• Floating 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; and

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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 Issue 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.

“Fitch” means Fitch Ratings Ltd. and any successor to its rating agency business.

“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 givingpro 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 apro 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 givingpro 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, thepro 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 givenpro 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 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 apro 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.

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“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.

“Guarantor” means each Restricted Subsidiary that Guarantees the Notes in accordance with the terms of the Indenture.

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“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;

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

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(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.

“Investment Grade Rating” means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s, 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. 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

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(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, Inc. 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).

“Junior Lien” means a Lien granted by a security document to the Collateral Trustee, at any time, upon any Collateral to secure Junior Lien Obligations.

“Junior Lien Debt” means:

(1) any Indebtedness (including letters of credit and reimbursement obligations with respect thereto) of the Issuer or any Guarantor that is secured on a subordinated basis to the Parity Lien Debt by a Junior Lien that was permitted to be incurred and so secured under each applicable Secured Debt Document;provided that:

(a) on or before the date on which such Indebtedness is incurred by the Issuer or such Guarantor, such Indebtedness is designated by the Issuer, in accordance with the Collateral Trust Agreement, as “Junior Lien Debt” for the purposes of the Secured Debt Documents, including the Collateral Trust Agreement;provided that no Series of Secured Lien Debt may be designated as both Junior Lien Debt and Parity Lien Debt;

(b) such Indebtedness is governed by an indenture, credit agreement or other agreement that includes a Lien Sharing and Priority Confirmation; and

(c) all requirements set forth in the Collateral Trust Agreement as to the confirmation, grant or perfection of the Collateral Trustee’s Liens to secure such Indebtedness or Obligations in respect thereof are satisfied (and the satisfaction of such requirements will be conclusively established if the Issuer delivers to the Collateral Trustee an officers’ certificate stating that such requirements have been satisfied and that such Indebtedness is “Junior Lien Debt”); and

(2) Hedging Obligations of the Issuer or any Guarantor incurred to hedge or manage interest rate risk with respect to Junior Lien Debt;provided that, pursuant to the terms of the Junior Lien Documents, such Hedging Obligations are secured by a Junior Lien on all of the assets and properties that secure the Indebtedness in respect of which such Hedging Obligations are incurred.

“Junior Lien Documents” means, collectively, any indenture, credit agreement or other agreement governing a Series of Junior Lien Debt and the Security Documents that create or perfect Liens securing Junior Lien Obligations.

“Junior Lien Obligations” means Junior Lien Debt and all other Obligations in respect thereof.

“Junior Lien Representative” means, in the case of any future Series of Junior Lien Debt, the trustee, agent or representative of the holders of such Series of Junior Lien Debt who (a) is appointed as a Junior Lien Representative (for purposes related to the administration of the Security Documents) pursuant to the indenture, credit agreement or other agreement governing such Series of Junior Lien Debt, together with its successors in such capacity, and (b) has become a party to the Collateral Trust Agreement by executing a joinder in the form required under the Collateral Trust Agreement.

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“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.

“Lien Sharing and Priority Confirmation” means:

(1) as to any Series of Parity Lien Debt, the written agreement enforceable against the holders of such Series of Parity Lien Debt, as set forth in the applicable Secured Debt Document:

(a) for the enforceable benefit of all holders of each existing and future Series of Parity Lien Debt and each existing and future Parity Lien Representative, that all Parity Lien Obligations will be and are secured equally and ratably by all Parity Liens at any time granted by the Issuer or any Guarantor to secure any Obligations in respect of such Series of Parity Lien Debt, and that all such Parity Liens will be enforceable by the Collateral Trustee for the benefit of all holders of Parity Lien Obligations equally and ratably;

(b) for the enforceable benefit of all holders of each existing and future Series of Parity Lien Debt and Series of Junior Lien Debt, and each existing and future Parity Lien Representative and Junior Lien Representative, that the holders of Obligations in respect of such Series of Parity Lien Debt are bound by the provisions of the Collateral Trust Agreement, including the provisions relating to the ranking of Parity Liens and the order of application of proceeds from enforcement of Parity Liens; and

(c) consenting to and directing the Collateral Trustee to perform its obligations under the Collateral Trust Agreement and the other security documents in respect of the Secured Debt Obligations.

(2) as to any Series of Junior Lien Debt, the written agreement enforceable against the holders of such Series of Junior Lien Debt, as set forth in the applicable Secured Debt Document:

(a) for the enforceable benefit of all holders of each existing and future Series of Junior Lien Debt and Series of Parity Lien Debt and each existing and future Junior Lien Representative and Parity Lien Representative, that all Junior Lien Obligations will be and are secured equally and ratably by all Junior Liens at any time granted by the Issuer or any Guarantor to secure any Obligations in respect of such Series of Junior Lien Debt, and that all such Junior Liens will be enforceable by the Collateral Trustee for the benefit of all holders of Junior Lien Obligations equally and ratably;

(b) for the enforceable benefit of all holders of each existing and future Series of Parity Lien Debt and Series of Junior Lien Debt and each existing and future Parity Lien Representative and Junior Lien Representative, that the holders of Obligations in respect of such Series of Junior Lien Debt are bound by the provisions of the Collateral Trust Agreement, including the provisions relating to the ranking of Junior Liens and the order of application of proceeds from the enforcement of Junior Liens; and

(c) consenting to and directing the Collateral Trustee to perform its obligations under the Collateral Trust Agreement and the other security documents in respect of the Secured Debt Obligations.

“Moody’s” means Moody’s Investors Service, Inc. and any successor to its rating agency business.

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“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 and Cash Equivalents received by the Issuer or any of its Restricted Subsidiaries in respect of any Asset Sale (including a Casualty Event), including any cash and Cash Equivalents received upon the sale 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 using proceeds from Asset Sales (other than Asset Sales of Collateral or other Oncor-related Assets) to the repayment of principal, premium, if any, and interest on other Senior Indebtedness required (other than required by clause (1) of the second paragraph under “— 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.

“Note Obligations” means the Notes, the Guarantees and all other Obligations of any of the Issuer and the Guarantors under the Indenture, the Notes, the Guarantees and the Security Documents.

“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 or other Person, as the case may be.

“Officer’s Certificate” means a certificate signed on behalf of the Issuer by an Officer of the Issuer or on behalf of another Person by an Officer of such Person, who must be the principal executive officer, the principal financial officer, the treasurer or the principal accounting officer of the Issuer or such Person, as applicable, that meets the requirements set forth in the Indenture.

“Oncor Electric Delivery Facility” means the revolving credit agreement 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.

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“Oncor-related Assets” means the Equity Interests in EFIH directly or indirectly owned by the Issuer, the Equity Interests of any of the Oncor Subsidiaries or any Successor Oncor Business (including the Collateral) owned by EFIH or any Oncor Subsidiary or any Successor Oncor Business or constituting a primary issuance of such Equity Interests to the extent such issuance would constitute an Asset Sale and any assets owned directly or indirectly by any of the Oncor Subsidiaries or any Successor Oncor Business.

“Oncor Subsidiaries” means Oncor Holdings and its Subsidiaries, all of which shall be Unrestricted Subsidiaries 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.

“Parity Lien” means a Lien granted by a security document to the Collateral Trustee, at any time, upon any Collateral to secure Parity Lien Obligations.

“Parity Lien Debt” means:

(1) the Guarantee by EFIH of the Notes issued on the Issue Date and any Additional Notes issued under the Indenture and any Exchange Notes related to such Notes or Additional Notes;

(2) the 9.75% Notes and any additional 9.75% Notes, any other Indebtedness (including letters of credit and reimbursement obligations with respect thereto) of EFIH, including the guarantee by EFIH of the 9.75% Notes and any additional 9.75% Notes and the EFIH Notes and any additional EFIH Notes, that is secured equally and ratably with EFIH’s Guarantee of the Notes by a Parity Lien that was permitted to be incurred and so secured under each applicable Secured Debt Document;provided, in the case of Indebtedness referred to in this clause (2), that, except with respect to the EFIH Notes:

(a) on or before the date on which such Indebtedness is incurred by the Issuer or such Guarantor, such Indebtedness is designated by the Issuer, in accordance with the Collateral Trust Agreement, as “Parity Lien Debt” for the purposes of the Secured Debt Documents;provided that no Series of Secured Lien Debt may be designated as both Parity Lien Debt and Junior Lien Debt;

(b) such Indebtedness is governed by an indenture, credit agreement or other agreement that includes a Lien Sharing and Priority Confirmation; and

(c) all requirements set forth in the Collateral Trust Agreement as to the confirmation, grant or perfection of the Collateral Trustee’s Lien to secure such Indebtedness or Obligations in respect thereof are satisfied (and the satisfaction of such requirements will be conclusively established if the Issuer delivers to the Collateral Trustee an Officer’s Certificate stating that such requirements have been satisfied and that such notes or such Indebtedness is “Parity Lien Debt”); and

(3) Hedging Obligations of the Issuer or any Guarantor incurred to hedge or manage interest rate risk with respect to Parity Lien Debt;provided that, pursuant to the terms of the Parity Lien Documents, such Hedging Obligations are secured by a Parity Lien on all of the assets and properties that secure the Indebtedness in respect of which such Hedging Obligations are incurred.

“Parity Lien Documents” means the Indenture, the 9.75% Notes Indenture, the EFIH Indenture and any additional indenture, credit agreement or other agreement governing a Series of Parity Lien Debt and the Security Documents that create or perfect Liens securing Parity Lien Obligations.

“Parity Lien Obligations” means Parity Lien Debt and all other Obligations in respect thereof.

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“Parity Lien Representative” means (1) the Trustee, in the case of the Notes, (2) The Bank of New York Mellon Trust Company, N.A., in the case of the EFIH Notes or (3) in the case of any other Series of Parity Lien Debt, the trustee, agent or representative of the holders of such Series of Parity Lien Debt who (a) is appointed as a Parity Lien Representative (for purposes related to the administration of the Security Documents) pursuant to the indenture, credit agreement or other agreement governing such Series of Parity Lien Debt, together with its successors in such capacity, and (b) has become a party to the Collateral Trust Agreement by executing a joinder in the form required under the Collateral Trust Agreement.

“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 Asset Transfer” means (1) the direct or indirect sale, assignment, transfer, conveyance or other disposition (including by way of merger, wind-up or consolidation) or spin-off by dividend of the Equity Interests of EFIH such that EFIH is no longer a Subsidiary of the Issuer (including without limitation a merger of EFIH with and into the Issuer) or (2) the sale, assignment, transfer, conveyance or other disposition (other than by way of merger, wind-up or consolidation) of all of the Equity Interests of, and other Investments in, the Oncor Subsidiaries, Successor Oncor Businesses and all other Collateral held by EFIH to a Person (other than an Oncor Subsidiary) that shall continue to hold such Equity Interests, other Investments and any other Collateral, in each case other than any foreclosure on the Collateral.

“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 were or at any time prior to the first anniversary of the Closing Date were 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 Issue Date;

(6) any Investment acquired by the Issuer or any of its Restricted Subsidiaries:

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(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 under “— 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 will not increase the amount available for Restricted Payments under clause (3) of the first paragraph under the covenant described under “— 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;

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(18) any Investment in Shell Wind or in other wind or other renewable energy projects or in any nuclear power or energy joint venture in an aggregate amount not to exceed $1,500.0 million at any time outstanding;

(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; and

(20) Investments in any nuclear power or energy joint venture in an aggregate amount not to exceed $200.0 million prior to receiving the requisite combined construction and operating license from the U.S. Nuclear Regulatory Commission in respect thereof.

“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 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;

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(7) Liens existing on the Issue 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;

(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;

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(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 “— 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;

(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;

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(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) through (14) above, including any capacity agreement; (C) any financial derivative agreement (including but not limited to swaps, options or swaptions) related to any commodity identified in subparts (1) through (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;

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(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 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.

“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.

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“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 each of Moody’s, S&P and Fitch, or if any of Moody’s, S&P or Fitch shall not make a rating on the Notes or other investment publicly available, a “nationally recognized statistical rating organization” within the meaning of Rule 15c3-1(c)(2)(vi)(F) under the Exchange Act selected by the Issuer which shall be substituted for Moody’s, S&P or Fitch, or all of them, 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.

“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 of the Notes issued on the Issue Date, 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 (A) except in the case of a Permitted Asset Swap of Collateral, assets (other than cash or Cash Equivalents) used or useful in, or securities of, a Similar Business;provided that any assets or securities received by the Issuer or a Restricted Subsidiary in exchange for assets or securities 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 and (B) in the case of a Permitted Asset Swap of Collateral, assets (other than cash or Cash Equivalents) used or useful in, or Capital Stock of, a Similar Oncor Business;provided that any Capital Stock received by EFIH in exchange for Collateral will not be deemed to be Related Business Assets, unless upon receipt of the Capital Stock of such Person, such Person would become a Subsidiary of EFIH or a joint venture in which EFIH has a significant equity interest (as determined by the Issuer in good faith).

“Required Junior Lien Debtholders” means, at any time, the holders of a majority in aggregate principal amount of all Junior Lien Debt (including outstanding letters of credit whether or not then available or drawn) then outstanding and the aggregate unfunded commitments to extend credit which, when funded, would constitute Junior Lien Debt, calculated in accordance with the provisions described under “— Security for the Notes — Voting.” For purposes of this definition, Junior Lien Debt registered in the name of, or beneficially owned by, the Issuer or any Affiliate of the Issuer will be deemed not to be outstanding.

“Required Parity Lien Debtholders” means, at any time, the holders of a majority in aggregate principal amount of all Parity Lien Debt (including outstanding letters of credit whether or not then available or drawn) then outstanding and the aggregate unfunded commitments to extend credit which, when funded, would constitute Parity Lien Debt, calculated in accordance with the provisions described under “— Security for the Notes — Voting.” For purposes of this definition, Parity Lien Debt registered in the name of, or beneficially owned by, the Issuer or any Affiliate of the Issuer will be deemed not to be outstanding.

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“Restoration Certificate”shall mean, with respect to any Casualty Event, an Officer’s Certificate provided to the Trustee prior to the 365th 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 Standard & Poor’s Financial Services LLC business, 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.

“SEC” means the U.S. Securities and Exchange Commission.

“Secured Debt Documents” means the Parity Lien Documents and the Junior Lien Documents.

“Secured Debt Obligations” means Parity Lien Obligations and Junior Lien Obligations.

“Secured Notes Issue Date” means November 16, 2009.

“Secured Indebtedness” means any Indebtedness of the Issuer or any of its Restricted Subsidiaries secured by a Lien.

“Secured Lien Debt” means Parity Lien Debt and Junior Lien Debt.

“Securities Act” means the Securities Act of 1933, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Security Documents” means the Collateral Trust Agreement, the Pledge Agreement, and all other security agreements, pledge agreements, collateral assignments, mortgages, collateral agency agreements, deed of trust or other grants or transfers for security executed and delivered by the Issuer, a Guarantor or any other obligor under the Notes creating (or purporting to create) a Lien upon Collateral in favor of the Collateral Trustee for the benefit of the holders of the Secured Debt Obligations, in each case, as amended, modified, renewed, restated or replaced, in whole or in part, from time to time, in accordance with its terms.

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“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 9.75% Notes and the related guarantees, the EFIH Notes 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 Issue 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) EFCH Floating Rate Junior Subordinated Debentures, Series D due 2037; or

(g) EFCH 8.175% Fixed Junior Subordinated Debentures, Series E due 2037.

“Series of Junior Lien Debt” means, severally, each issue or series of Junior Lien Debt for which a single transfer register is maintained (provided that any Hedging Obligations constituting Junior Lien Debt shall be deemed part of the Series of Junior Lien Debt to which it relates).

“Series of Parity Lien Debt” means, severally, the Notes, the 9.75% Notes, the EFIH Notes and any Additional Notes or Exchange Notes or other Indebtedness that constitutes Parity Lien Debt (provided that any Hedging Obligations constituting Parity Lien Debt shall be deemed part of the Series of Parity Lien Debt to which it relates).

“Series of Secured Lien Debt” means each Series of Parity Lien Debt and each Series of Junior Lien Debt.

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“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.

“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.

“Similar Oncor Business” means any business which is primarily engaged in a regulated electricity or other energy transmission or distribution business in the United States (as determined by the Issuer in good faith).

“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.

“Successor Oncor Business” means any Person the Capital Stock of which is received by EFIH in an Asset Sale, including a Permitted Asset Swap, of Collateral or as a dividend or distribution from an Oncor Subsidiary.

“TCEH” means Texas Competitive Electric Holdings Company LLC.

“TCEH Notes” means the 10.25% Senior Notes due 2015, the 10.25% Senior Notes due 2015, Series B and the 10.50%/11.25% Senior Toggle Notes due 2016, in each case issued by TCEH and TCEH Finance, Inc., including the guarantees thereof and PIK interest which has been or may be paid with respect thereto.

“TCEH Senior Interim Facility” means the interim loan agreement, dated as of the Closing Date by and among EFCH, 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.

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“TCEH Senior Secured Facilities” means the credit agreement dated as of the Closing Date, as amended on August 7, 2009, by and among EFCH, 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 additional 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 Transfer” means the sale, transfer, disposition or spin-off (including by way of merger, wind-up or consolidation) of (a) the membership interests or other common Equity Interests of EFCH, TCEH or another Restricted Subsidiary that holds all or substantially all of the assets of TCEH and its Subsidiaries such that EFCH, TCEH or such Restricted Subsidiary ceases to be a Subsidiary of the Issuer or (b) all or substantially all of the assets of TCEH and its Subsidiaries, in each case other than any such transfer to a Restricted Subsidiary of the Issuer.

“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, any repayments of indebtedness of the Issuer and its Restricted Subsidiaries in connection therewith, and the issuance of the 10.875% Senior Notes due 2017, 11.250%/12.000% Senior Toggle Notes due 2017, the TCEH Notes 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 the Issuer.

“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 January 15, 2015;provided, however, that if the period from the Redemption Date to January 15, 2015 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.

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“Unrestricted Subsidiary” means:

(1) each of the Oncor Subsidiaries, Comanche Peak Nuclear Power Company, Nuclear Energy Future Holdings LLC and Nuclear Energy Future Holdings II LLC;

(2) any Subsidiary of the Issuer other than EFIH or any other Guarantor owning Collateral 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) other than EFIH or any other Guarantor owning Collateral 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;

(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 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 apro 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.

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“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 UNITED STATES FEDERAL INCOME TAX CONSEQUENCES

Federal Income Tax Considerations of the Exchange of Outstanding Notes for Exchange Notes

The following discussion is a summary of certain federal income tax considerations relevant to the exchange of outstanding notes for exchange notes, but does not purport to be a complete analysis of all potential tax effects. This discussion is based upon the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), applicable Treasury Regulations promulgated and proposed thereunder, judicial authority and administrative interpretations, as of the date hereof, all of which are subject to change, possibly with retroactive effect, or are subject to different interpretations. This discussion does not address the tax considerations arising under the laws of any foreign, state, local, or other jurisdiction.

We believe that the exchange of outstanding notes for exchange notes should not be an exchange or otherwise a taxable event to a holder for United States federal income tax purposes. Accordingly, a holder should not recognize gain or loss upon receipt of exchange notes, and a holder should have the same adjusted issue price, adjusted basis and holding period in the exchange notes as it had in the outstanding notes 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 United States federal income tax consequences in light of their particular situations as well as any consequences arising under the laws of any other taxing jurisdiction.

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CERTAIN ERISA CONSIDERATIONS

This disclosure was written in connection with the promotion and marketing of the notes by EFH Corp. and the initial purchasers, and it cannot be used by any holder for the purpose of avoiding penalties that may be asserted against the holder under the Code. Prospective purchasers of the notes should consult their own tax advisors with respect to the application of the U.S. federal income tax laws to their particular situations.

The following is a summary of certain considerations associated with the purchase of the notes and exchange notes by employee benefit plans that are subject to Title I of ERISA, individual retirement accounts and other plans and arrangements that are subject to Section 4975 of the Code or provisions under any federal, state, local, non-U.S. or other laws 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 plan, account or arrangement (each, a “Plan”).

This summary is based on the provisions of ERISA and the Code (and related regulations and administrative and judicial interpretations) as of the date of this prospectus. This summary does not purport to be complete and future legislation, court decisions, administrative regulations, rulings or administrative pronouncements could significantly modify the requirements summarized below. Any of these changes may be retroactive and may thereby apply to transactions entered into prior to the date of their enactment or release.

General Fiduciary Matters

ERISA imposes certain duties on persons who are fiduciaries of a Plan subject to Title I of ERISA or of a Plan subject to Section 4975 of the Code (each, a “Benefit Plan”) and both ERISA and the Code prohibit certain transactions involving the assets of a Benefit Plan and its fiduciaries or other interested parties. Under ERISA and the Code, any person who exercises any discretionary authority or control over the administration of such a Benefit Plan or the management or disposition of the assets of such a Benefit Plan, or who renders investment advice for a fee or other compensation to such a Benefit Plan, is generally considered to be a fiduciary of the Benefit Plan.

In considering an investment in the notes of a portion of the assets of any Plan, a fiduciary should consult with its counsel in order to 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. In addition, a fiduciary of a Plan should consult with its counsel in order to determine if the investment satisfies the 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.

Prohibited Transaction Issues

Section 406 of ERISA and Section 4975 of the Code prohibit Benefit 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 the Code. In addition, the fiduciary of the Benefit Plan that engaged in such a nonexempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Code. The acquisition and/or holding of notes by a Benefit Plan with respect to which EFH Corp., a guarantor or the initial purchasers 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. In this regard, the United States Department of Labor has issued prohibited transaction class exemptions (“PTCEs”) that may apply to the acquisition and holding of the notes. These class exemptions include, without limitation, 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.

314

Each of these PTCEs contains conditions and limitations on its application. Fiduciaries of Plans considering acquiring and/or holding the notes in reliance of these or any other PTCE should carefully review the PTCE to assure it is applicable. 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 purchased or held by any person investing “plan assets” of any Plan, unless such purchase and holding (and the exchange of notes for exchange notes) are entitled to exemption relief from the prohibited transaction provisions of ERISA and the Code and are otherwise permissible under all applicable Similar Laws.

Representation

Accordingly, by acceptance of a note or an exchange note, or any interest therein, each purchaser and subsequent transferee will be deemed to have represented and warranted that either (i) no portion of the assets used by such purchaser or transferee to acquire or hold the notes constitutes assets of any Plan or (ii) the acquisition and holding of the notes (and the exchange of notes for exchange notes) by such purchaser or transferee are entitled to exemptive relief from the prohibited transaction provisions of Section 406 of ERISA and Section 4975 of the Code and are otherwise permissible under all 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 the notes (and holding the notes or exchange 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 investments and whether an exemption would be applicable to the purchase and holding of the notes and the exchange of notes for exchange notes.

315

PLAN OF DISTRIBUTION

Each broker-dealer that receives exchange notes for its own account pursuant to the 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 180 days after the consummation of the exchange offer, 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 the 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 180 days after the consummation of the exchange offer, 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 offer (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.

316

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 150,000 shares of common stock of EFH Corp., including 100,000 shares issuable upon exercise of options. In addition, Mr. Wright has stock options to purchase an additional 150,000 shares of common stock of EFH Corp. that will not vest within 60 days, with 50,000 of such additional shares to be purchased at a price per share equal to $5.00 and 100,000 of such additional shares to be purchased at a price per share equal to $3.50.

EXPERTS

The consolidated financial statements as of December 31, 2009 and 2008 (successor), and for the years ended December 31, 2009 and 2008 (successor), the period from October 11, 2007 through December 31, 2007 (successor) and the period from January 1, 2007 through October 10, 2007 (predecessor) of EFH Corp., included in this prospectus, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein, (which report expresses an unqualified opinion on the financial statements and includes an explanatory paragraph related to EFH Corp. completing its merger with Texas Energy Future Merger Sub Corp (Merger Sub) and becoming a subsidiary of Texas Energy Future Holdings Limited Partnership on October 10, 2007). Also, the consolidated financial statements as of December 31, 2009 and 2008 (successor balance sheets), and for the years ended December 31, 2009 and 2008, the period from October 11, 2007 through December 31, 2007 (successor operations) of Oncor Holdings and the financial statements for the period from January 1, 2007 through October 10, 2007 (predecessor operations) of Oncor (as Oncor Holdings’ predecessor) included in this prospectus, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion and includes an explanatory paragraph referring to Oncor Holdings as an indirect subsidiary of EFH Corp., which was merged with Merger Sub on October 10, 2007). Such financial statements have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

317

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

Adjusted EBITDA Adjusted EBITDA means EBITDA adjusted to exclude non-cash items, unusual items and other adjustments allowable under certain of our debt arrangements. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under U.S. GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA in this prospectus (see reconciliations in “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010 — Covenants and Restrictions Under Financing Arrangements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Year Ended December 31, 2009 — Covenants and Restrictions Under Financing Arrangements”) solely because of the important role that Adjusted EBITDA plays in respect of certain covenants contained in our debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with U.S. GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.

ancillary services Refers to services necessary to support the transmission of energy and maintain reliable operations for the entire transmission system

baseload Refers to the minimum constant level of electricity demand in a system, such as ERCOT, and/or to the electricity generation facilities or capacity normally expected to operate continuously throughout the year to serve such demand, such as our nuclear and lignite/coal-fueled generation units

Capgemini Energy Capgemini Energy LP, a subsidiary of Cap Gemini North America Inc. that provides business support services to EFH Corp. and its subsidiaries

Competitive Electric segment Refers to the EFH Corp. business segment that consists principally of TCEH.

318

CREZ Competitive Renewable Energy Zone

DOE US Department of Energy

EBITDA Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. See the definition of Adjusted EBITDA above.

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

Fitch Fitch Ratings, Ltd. (a credit rating agency)

GAAP generally accepted accounting principles

GWh gigawatt-hours

IRS U.S. Internal Revenue Service

kV kilovolts

kWh kilowatt-hours

Luminant Construction Refers to the operations of TCEH established for the purpose of developing and constructing new generation facilities.

Luminant Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.

market heat rate Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.

MMBtu million British thermal units

Moody’s Moody’s Investors Services, Inc. (a credit rating agency)

MWh megawatt-hours

319

Oncor Ring-Fenced Entities Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor.

price-to-beat 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

purchase accounting The purchase method of accounting for a business combination as prescribed by U.S. GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill

Regulated Delivery segment Refers to the EFH Corp. business segment that consists of the operations of Oncor.

REP retail electric provider

S&P Standard & Poor’s Ratings Services, a division of the McGraw Hill Companies Inc. (a credit rating agency)

SG&A selling, general and administrative

TCEH Senior Secured Facilities Refers collectively to the TCEH Initial Term Loan Facility, TCEH Delayed Draw Term Loan Facility, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 6 to EFH Corp.’s historical consolidated financial statements for the three and nine months ended September 30, 2010 for details of these facilities

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Audited Consolidated Financial Statements of Energy Future Holdings Corp.
Report of Independent Registered Public Accounting Firm		F-1
Glossary		F-2
Statements of Consolidated Income (Loss) for the years ended December 31, 2009 and 2008 (Successor), the period from October  11, 2007 through December 31, 2007 (Successor) and the period from January 1, 2007 through October 10, 2007 (Predecessor)		F-7
Statements of Consolidated Comprehensive Income (Loss) for the years ended December 31, 2009 and 2008 (Successor), the period from October  11, 2007 through December 31, 2007 (Successor) and the period from January 1, 2007 through October 10, 2007 (Predecessor)		F-8
Statements of Consolidated Cash Flows for the years ended December 31, 2009 and 2008 (Successor), the period from October  11, 2007 through December 31, 2007 (Successor) and the period from January 1, 2007 through October 10, 2007 (Predecessor)		F-9
Consolidated Balance Sheets as of December 31, 2009 (Successor) and December 31, 2008 (Successor)		F-12
Statements of Consolidated Equity for the years ended December 31, 2009 and 2008 (Successor), the period from October  11, 2007 through December 31, 2007 (Successor), the period from January 1, 2007 through October 10, 2007 (Predecessor)		F-13
Notes to Consolidated Financial Statements		F-15
Unaudited Condensed Consolidated Financial Statements of Energy Future Holdings Corp.
Glossary		F-94
Condensed Statements of Consolidated Income (Loss) for the three and nine months ended September 30, 2010 and 2009		F-98
Condensed Statements of Consolidated Comprehensive Income (Loss) for the three and nine months ended September 30, 2010 and 2009		F-99
Condensed Statements of Consolidated Cash Flows for the nine months ended September 30, 2010 and 2009		F-100
Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009		F-102
Notes to Condensed Consolidated Financial Statements		F-103
Audited Consolidated Financial Statements of Oncor Electric Delivery Holdings Company LLC (Successor) and Oncor Electric Delivery Company LLC (Predecessor)
Glossary		F-156
Report of Independent Registered Public Accounting Firm		F-159
Statements of Consolidated Income (Loss) for the years ended December 31, 2009 and 2008 (Successor), the period from October  11, 2007 through December 31, 2007 (Successor) and the period from January 1, 2007 through October 10, 2007 (Predecessor)		F-160
Statements of Consolidated Comprehensive Income (Loss) for the years ended December 31, 2009 and 2008 (Successor), the period from October  11, 2007 through December 31, 2007 (Successor) and the period from January 1, 2007 through October 10, 2007 (Predecessor)		F-161

Statements of Consolidated Cash Flows for the years ended December 31, 2009 and 2008 (Successor), the period from October  11, 2007 through December 31, 2007 (Successor) and the period from January 1, 2007 through October 10, 2007 (Predecessor)	F-162
Consolidated Balance Sheets as of December 31, 2009 (Successor) and December 31, 2008 (Successor)	F-164
Statements of Consolidated Membership Interests for the years ended December 31, 2009 and 2008 (Successor) and the period from October  11, 2007 through December 31, 2007 (Successor)	F-165
Statement of Consolidated Shareholder’s Equity for the period from January 1, 2007 through October 10, 2007 (Predecessor)	F-166
Notes to Consolidated Financial Statements	F-167
Unaudited Condensed Consolidated Financial Statements of Oncor Electric Delivery Holdings Company LLC
Glossary	F-197
Condensed Statements of Consolidated Income for the three and nine months ended September 30, 2010 and 2009	F-199
Condensed Statements of Consolidated Cash Flows for the nine months ended September 30, 2010 and 2009	F-200
Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009	F-201
Notes to Condensed Consolidated Financial Statements	F-202

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Dallas, Texas

We have audited the accompanying consolidated balance sheets of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) as of December 31, 2009 and 2008 (successor), and the related statements of consolidated income (loss), comprehensive income (loss), cash flows and equity for the years ended December 31, 2009 and 2008 (successor), the period from October 11, 2007 through December 31, 2007 (successor) and the period from January 1, 2007 through October 10, 2007 (predecessor). These financial statements are the responsibility of EFH Corp.’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Energy Future Holdings Corp. and subsidiaries as of December 31, 2009 and 2008 (successor), and the results of their operations and their cash flows for the years ended December 31, 2009 and 2008 (successor), the period from October 11, 2007 through December 31, 2007 (successor) and the period from January 1, 2007 through October 10, 2007 (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.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), EFH Corp.’s internal control over financial reporting as of December 31, 2009, based on the criteria established inInternal Control —Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report (not presented herein) dated February 18, 2010 expressed an unqualified opinion on EFH Corp.’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Dallas, Texas

February 18, 2010

F-1

GLOSSARY

When the following terms and abbreviations appear in the text of these financial statements, 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

2008 Form 10-K EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2008 as recast in a Current Report on Form 8-K filed on May 20, 2009 to reflect the adoption of new accounting and disclosure guidance related to noncontrolling interests

Adjusted EBITDA Adjusted EBITDA means EBITDA adjusted to exclude non-cash items, unusual items and other adjustments allowable under certain of our debt arrangements. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA elsewhere herein (see reconciliations in “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Year Ended December 31, 2009 — Covenants and Restrictions Under Financing Arrangements”) solely because of the important role that Adjusted EBITDA plays in respect of certain covenants contained in our debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.

Ancillary services Refers to services necessary to support the transmission of energy and maintain reliable operations for the entire transmission system.

CAIR Clean Air Interstate Rule

Capgemini Capgemini Energy LP, a provider of business support services to EFH Corp. and its subsidiaries

CO2 carbon dioxide

Competitive Electric segment Refers to the EFH Corp. business segment that consists principally of TCEH.

CREZ Competitive Renewable Energy Zone

DOE US Department of Energy

EBITDA Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. See the definition of Adjusted EBITDA above.

F-2

EFC Holdings Refers to Energy Future Competitive Holdings Company, a direct subsidiary of EFH Corp. and the direct parent of TCEH.

EFH Corp. Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include TCEH and Oncor.

EFH Corp. Senior Notes Refers collectively to EFH Corp.’s 10.875% Senior Notes due November 1, 2017 (EFH Corp. 10.875% Notes) and EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes).

EFH Corp. 9.75% Notes Refers to EFH Corp.’s 9.75% Senior Secured Notes due October 15, 2019.

EFIH Finance Refers to EFIH Finance Inc., a direct, wholly-owned subsidiary of Intermediate Holding, formed for the sole purpose of serving as co-issuer with Intermediate Holding of certain debt securities.

EFIH Notes Refers to Intermediate Holding’s and EFIH Finance’s 9.75% Senior Secured Notes due October 15, 2019.

EPA US Environmental Protection Agency

EPC engineering, procurement and construction

ERCOT Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas

ERISA Employee Retirement Income Security Act of 1974, as amended

FASB Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting

FERC US Federal Energy Regulatory Commission

Fitch Fitch Ratings, Ltd. (a credit rating agency)

GAAP generally accepted accounting principles

GHG greenhouse gas

GWh gigawatt-hours

Intermediate Holding Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.

IRS US Internal Revenue Service

kV kilovolts

kWh kilowatt-hours

LIBOR London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market.

F-3

Luminant Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.

Market heat rate Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.

Merger The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007.

Merger Agreement Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.

Merger Sub Texas Energy Future Merger Sub Corp, a Texas corporation and a wholly-owned subsidiary of Texas Holdings that was merged into EFH Corp. on October 10, 2007

MMBtu million British thermal units

Moody’s Moody’s Investors Services, Inc. (a credit rating agency)

MW megawatts

MWh megawatt-hours

NERC North American Electric Reliability Corporation

NOx nitrogen oxide

NRC US Nuclear Regulatory Commission

Oncor Refers to Oncor Electric Delivery Company LLC, a direct majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities.

Oncor Holdings Refers to Oncor Electric Delivery Holdings Company LLC, a direct wholly-owned subsidiary of Intermediate Holding and the direct majority owner of Oncor, that is consolidated as a variable interest entity under consolidations accounting standards.

Oncor Ring-Fenced Entities Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor.

F-4

OPEB other postretirement employee benefits

PUCT Public Utility Commission of Texas

PURA Texas Public Utility Regulatory Act

Purchase accounting The purchase method of accounting for a business combination as prescribed by GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.

Regulated Delivery segment Refers to the EFH Corp. business segment, which consists of the operations of Oncor.

REP retail electric provider

RRC Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas

S&P Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies Inc. (a credit rating agency)

SARs Stock Appreciation Rights

SARs Plan Refers to the Oncor Electric Delivery Company Stock Appreciation Rights Plan

SEC US Securities and Exchange Commission

Securities Act Securities Act of 1933, as amended

SG&A selling, general and administrative

SO2 sulfur dioxide

Sponsor Group Collectively, the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P. (KKR), 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 subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy markets activities. Its major subsidiaries include Luminant and TXU Energy.

TCEH Finance Refers to TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities.

TCEH Senior Notes Refers collectively to TCEH’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes Series B due November 1, 2015 (collectively, TCEH 10.25% Notes) and TCEH’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes).

F-5

TCEH Senior Secured Facilities Refers collectively to the TCEH Initial Term Loan Facility, TCEH Delayed Draw Term Loan Facility, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 12 for details of these facilities.

TCEQ Texas Commission on Environmental Quality

Texas Holdings Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.

Texas Holdings Group Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities.

Texas Transmission Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of its subsidiaries or any member of the Sponsor Group.

TXU Energy Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT.

TXU Europe TXU Europe Limited, a subsidiary of EFH Corp. that is in administration (similar to bankruptcy) in the United Kingdom

TXU Fuel TXU Fuel Company, a former subsidiary of TCEH

TXU Gas TXU Gas Company, a former subsidiary of EFH Corp.

US United States of America

F-6

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Millions of Dollars)

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Operating revenues	$	9,546		$	11,364		$	1,994		$	8,044
Fuel, purchased power costs and delivery fees		(2,878	)		(4,595	)		(644	)		(2,381	)
Net gain (loss) from commodity hedging and trading activities		1,736			2,184			(1,492	)		(554	)
Operating costs		(1,598	)		(1,503	)		(306	)		(1,107	)
Depreciation and amortization		(1,754	)		(1,610	)		(415	)		(634	)
Selling, general and administrative expenses		(1,068	)		(957	)		(216	)		(691	)
Franchise and revenue-based taxes		(359	)		(363	)		(93	)		(282	)
Impairment of goodwill (Note 3)		(90	)		(8,860	)		—			—
Other income (Note 10)		204			80			14			69
Other deductions (Note 10)		(97	)		(1,301	)		(61	)		(841	)
Interest income		45			27			24			56
Interest expense and related charges (Note 25)		(2,912	)		(4,935	)		(839	)		(671	)
Income (loss) from continuing operations before income taxes		775			(10,469	)		(2,034	)		1,008
Income tax (expense) benefit		(367	)		471			673			(309	)
Income (loss) from continuing operations		408			(9,998	)		(1,361	)		699
Income from discontinued operations, net of tax effect (Note 1)		—			—			1			24
Net income (loss)		408			(9,998	)		(1,360	)		723
Net (income) loss attributable to noncontrolling interests		(64	)		160			—			—
Net income (loss) attributable to EFH Corp.	$	344		$	(9,838	)	$	(1,360	)	$	723

See Notes to Financial Statements.

F-7

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Millions of Dollars)

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Net income (loss)	$	408		$	(9,998	)	$	(1,360	)	$	723
Other comprehensive income (loss), net of tax effects:
Reclassification of pension and other retirement benefit costs (net of tax (expense) benefit of $20, $69, $5, and $(19)) (Note 21)		(40	)		(84	)		(57	)		49
Cash flow hedges:
Net decrease in fair value of derivatives (net of tax benefit of $10, $99, $97 and $154)		(20	)		(183	)		(177	)		(288	)
Derivative value net (gains) losses related to hedged transactions recognized during the period and reported in net income (net of tax (expense) benefit of $72, $66, $— and $(48))		130			122			—			(89	)
Total effect of cash flow hedges		110			(61	)		(177	)		(377	)
Total adjustments to net income (loss)		70			(145	)		(234	)		(328	)
Comprehensive income (loss)		478			(10,143	)		(1,594	)		395
Comprehensive (income) loss attributable to noncontrolling interests		(64	)		160			—			—
Comprehensive income (loss) attributable to EFH Corp.	$	414		$	(9,983	)	$	(1,594	)	$	395

See Notes to Financial Statements.

F-8

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

	Successor									Predecessor
	Year Ended December  31, 2009			Year Ended December  31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Cash flows — operating activities
Net income (loss)	$	408		$	(9,998	)	$	(1,360	)	$	723
Income from discontinued operations, net of tax effect		—			—			(1	)		(24	)
Income (loss) from continuing operations		408			(9,998	)		(1,361	)		699
Adjustments to reconcile income from continuing operations to cash provided by operating activities:
Depreciation and amortization		2,172			2,070			568			684
Deferred income tax expense (benefit) — net		253			(477	)		(736	)		(111	)
Impairment of goodwill (Note 3)		90			8,860			—			—
Impairment of trade name intangible asset (Note 3)		—			481			—			—
Impairment of emission allowances intangible assets (Note 3)		—			501			—			—
Impairment of natural gas-fueled generation facilities (Note 5)		—			229			—			—
Impairment of land (Note 10)		34			—			—			—
Charge related to Lehman bankruptcy (Note 10)		—			26			—			—
Write off of regulatory assets (Note 25)		25			—			—			—
Increase of Toggle Notes in lieu of cash interest (Note 12)		511			—			—			—
Unrealized net (gains) losses from mark-to-market valuations of commodity positions		(1,225	)		(2,329	)		1,556			722
Unrealized net (gains) losses from mark-to-market valuations of interest rate swaps		(696	)		1,477			—			—
Net gain on debt exchanges (Note 12)		(87	)		—			—			—
Bad debt expense (Note 11)		113			81			12			46
Stock-based incentive compensation expense		14			30			—			27
Reversal of reserves recorded in purchase accounting (Note 10)		(44	)		—			—			—
Losses on dedesignated cash flow hedges (interest rate swaps)		184			66			—			10
Net charges related to cancelled development of generation facilities (Note 4)		—			—			2			676
Write-off of deferred transaction costs (Note 10)		—			—			—			38
Credit related to impaired leases (Note 10)		—			—			—			(48	)
Net gains on sale of assets, including amortization of deferred gains		(5	)		(1	)		(1	)		(40	)
Other, net		(4	)		(20	)		5			19
Changes in operating assets and liabilities:
Accounts receivable — trade		(125	)		(505	)		309			(200	)
Impact of accounts receivable sales program (Note 11)		(33	)		53			(336	)		72
Inventories		(59	)		(21	)		(5	)		(7	)
Accounts payable — trade		(141	)		385			(264	)		81
Commodity and other derivative contractual assets and liabilities		(64	)		(28	)		18			(185	)
Margin deposits — net		248			595			(614	)		(569	)
Deferred advanced metering system revenues (Note 25)		57			—			—			—
Other — net assets		(43	)		440			284			(89	)
Other — net liabilities		128			(410	)		113			440
Cash provided by (used in) operating activities from continuing operations	$	1,711		$	1,505		$	(450	)	$	2,265

F-9

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS (Cont’d)

(Millions of Dollars)

	Successor									Predecessor
	Year Ended December  31, 2009			Year Ended December  31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Cash flows — financing activities
Issuances of long-term debt/securities (Note 12):
Equity financing from Sponsor Group and other investors	$	—		$	—		$	8,236		$	—
Merger-related debt financing		—			—			42,732			1,800
Pollution control revenue bonds		—			242			—			—
Oncor long-term debt		—			1,500			—			—
Other long-term debt		522			1,443			—			—
Common stock		—			34			—			1
Repayments/repurchases of long-term debt/securities (Note 12):
Pollution control revenue bonds		—			(242	)		—			(143	)
Merger-related debt repurchases		—			—			(15,314	)		—
Other long-term debt		(396	)		(925	)		(81	)		(302	)
Common stock		—			(3	)		—			(13	)
Increase (decrease) in short-term borrowings (Note 12):
Banks		332			(481	)		(722	)		2,245
Commercial paper		—			—			—			(1,296	)
Proceeds from sale of noncontrolling interests, net of transaction costs (Note 15)		—			1,253			—			—
Contributions from noncontrolling interests		48			—			—			—
Distributions paid to noncontrolling interests		(56	)		(2	)		—			—
Common stock dividends paid		—			—			—			(788	)
Settlements of minimum withholding tax liabilities under stock-based compensation plans		—			—			—			(93	)
Debt discount, financing and reacquisition expenses		(49	)		(21	)		(986	)		(17	)
Other, net		21			39			—			—
Cash provided by financing activities from continuing operations	$	422		$	2,837		$	33,865		$	1,394

F-10

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS (Cont’d)

(Millions of Dollars)

	Successor									Predecessor
	Year Ended December  31, 2009			Year Ended December  31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Cash flows — investing activities
Acquisition of EFH Corp.	$	—		$	—		$	(32,694	)	$	—
Capital expenditures		(2,348	)		(2,849	)		(693	)		(2,366	)
Nuclear fuel purchases		(197	)		(166	)		(23	)		(54	)
Money market fund redemptions (investments) (Note 1)		142			(142	)		—			—
Investment posted with derivative counterparty (Note 18)		(400	)		—			—			—
Reduction of (proceeds from) letter of credit facility deposited with trustee (restricted cash) (Note 12)		115			—			(1,250	)		—
Reduction of restricted cash related to pollution control revenue bonds		—			29			13			202
Other changes in restricted cash		9			1			14			(16	)
Purchase of mining-related assets		—			—			—			(122	)
Proceeds from sale of assets		2			80			86			71
Proceeds from sale of controlling interest in natural gas gathering pipeline business		40			—			—			—
Proceeds from sale of environmental allowances and credits		19			39			—			—
Purchases of environmental allowances and credits		(19	)		(34	)		—			—
Cash settlements related to outsourcing contract termination (Note 20)		—			70			—			—
Settlement of loan (Note 20)		—			25			—			—
Proceeds from sales of nuclear decommissioning trust fund securities		3,064			1,623			831			602
Investments in nuclear decommissioning trust fund securities		(3,080	)		(1,639	)		(835	)		(614	)
Other, net		20			29			(12	)		14
Cash used in investing activities from continuing operations	$	(2,633	)	$	(2,934	)	$	(34,563	)	$	(2,283	)
Discontinued operations:
Cash provided by (used in) operating activities		—			—			(7	)		35
Cash used in financing activities		—			—			—			—
Cash provided by (used in) investing activities		—			—			—			—
Cash provided by (used in) discontinued operations		—			—			(7	)		35
Net change in cash and cash equivalents		(500	)		1,408			(1,155	)		1,411
Cash and cash equivalents — beginning balance		1,689			281			1,436			25
Cash and cash equivalents — ending balance	$	1,189		$	1,689		$	281		$	1,436

See Notes to Financial Statements.

F-11

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

	Successor
	December 31, 2009			December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents (Note 1)	$	1,189		$	1,689
Investment posted with counterparty (Note 18)		425			—
Investments held in money market fund (Note 1)		—			142
Restricted cash (Note 25)		48			55
Trade accounts receivable — net (Note 11)		1,260			1,219
Income taxes receivable — net		—			42
Inventories (Note 25)		485			426
Commodity and other derivative contractual assets (Note 18)		2,391			2,534
Accumulated deferred income taxes (Note 9)		5			44
Margin deposits related to commodity positions		187			439
Other current assets		136			165
Total current assets		6,126			6,755
Restricted cash (Note 25)		1,149			1,267
Investments (Note 19)		750			645
Property, plant and equipment — net (Note 25)		30,108			29,522
Goodwill (Note 3)		14,316			14,386
Intangible assets — net (Note 3)		2,876			2,993
Regulatory assets — net (Note 25)		1,959			1,892
Commodity and other derivative contractual assets (Note 18)		1,533			962
Other noncurrent assets, principally unamortized debt issuance costs		845			841
Total assets	$	59,662		$	59,263
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (Note 12)	$	1,569		$	1,237
Long-term debt due currently (Note 12)		417			385
Trade accounts payable		896			1,143
Commodity and other derivative contractual liabilities (Note 18)		2,392			2,908
Margin deposits related to commodity positions		520			525
Accrued interest		526			524
Other current liabilities		744			612
Total current liabilities		7,064			7,334
Accumulated deferred income taxes (Note 9)		6,131			6,067
Investment tax credits		37			42
Commodity and other derivative contractual liabilities (Note 18)		1,060			2,095
Long-term debt, less amounts due currently (Note 12)		41,440			40,838
Other noncurrent liabilities and deferred credits (Note 25)		5,766			5,205
Total liabilities		61,498			61,581
Commitments and Contingencies (Note 13)
Equity (Note 14):
EFH Corp. shareholders’ equity		(3,247	)		(3,673	)
Noncontrolling interests in subsidiaries		1,411			1,355
Total equity		(1,836	)		(2,318	)
Total liabilities and equity	$	59,662		$	59,263

See Notes to Financial Statements.

F-12

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED EQUITY

(Millions of Dollars)

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Common stock stated value of $0.001 effective May 2009 (number of authorized shares — Successor — 2,000,000,000; Predecessor — 1,000,000,000):
Balance at beginning of period	$	—		$	—		$	—		$	5
Effects of shareholder actions related to stated value of common stock		2			—			—			—
Balance at end of period (number of shares outstanding: Successor: 2009 — 1,668,065,133; 2008 — 1,667,149,663; 2007 — 1,664,345,953; Predecessor: October 10, 2007 — 461,152,009		2			—			—			5
Additional paid-in capital:
Balance at beginning of period		7,904			8,279			—			1,104
Investment by Sponsor Group and other investors		—			—			8,279			—
Effects of stock-based incentive compensation plans		11			29			—			(66	)
Effects of shareholder actions related to stated value of common stock		(2	)		—			—			—
Effect of sale of noncontrolling interests (Note 15)		—			(406	)		—			—
Common stock repurchases		—			—			—			(13	)
Excess tax benefit on stock-based compensation		—			—			—			82
Cost of Thrift Plan shares released by LESOP trustee (Note 21)		—			—			—			210
Effects of executive deferred compensation plan		—			—			—			11
Other		1			2			—			(2	)
Balance at end of period		7,914			7,904			8,279			1,326
Retained earnings (deficit):
Balance at beginning of period		(11,198	)		(1,360	)		—			622
Net income (loss) attributable to EFH Corp		344			(9,838	)		(1,360	)		723
Dividends declared on common stock ($—, $—, $—, and $1.30 per share)		—			—			—			(596	)
Effect of adoption of accounting guidance related to uncertain tax positions (Note 8)		—			—			—			33
LESOP dividend deduction tax benefit and other		—			—			—			3
Balance at end of period		(10,854	)		(11,198	)		(1,360	)		785
Accumulated other comprehensive gain (loss), net of tax effects:
Pension and other postretirement employee benefit liability adjustments:
Balance at beginning of period		(141	)		(57	)		—			(2	)
Change in unrecognized gains (losses) related to pension and other retirement benefit costs		(40	)		(84	)		(57	)		49
Balance at end of period		(181	)		(141	)		(57	)		47
Amounts related to cash flow hedges:
Balance at beginning of period		(238	)		(177	)		—			411
Change during the period		110			(61	)		(177	)		(377	)
Balance at end of period		(128	)		(238	)		(177	)		34
Total accumulated other comprehensive gain (loss) at end of period		(309	)		(379	)		(234	)		81
EFH Corp. shareholders’ equity at end of period (Note 14)		(3,247	)		(3,673	)		6,685			2,197
Noncontrolling interests in subsidiaries (Note 15):
Balance at beginning of period		1,355			—			—			—
Net income (loss) attributable to noncontrolling interests		64			(160	)		—			—
Investment		48			1,253			—			—

F-13

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED EQUITY (Millions of Dollars)

	Successor								Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007		Period from January 1, 2007 through October 10, 2007
Effect of sale of noncontrolling interests		—			265			—		—
Distributions to noncontrolling interests		(56	)		(2	)		—		—
Other		—			(1	)		—		—
Noncontrolling interests in subsidiaries at end of period		1,411			1,355			—		—
Total equity at end of period	$	(1,836	)	$	(2,318	)	$	6,685	$	2,197

See Notes to Financial Statements.

F-14

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

EFH Corp., a Texas corporation, is a Dallas-based holding company conducting its operations principally through its TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority (approximately 80%) owned subsidiary 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. See Note 2.

References in these financial statements to “we,” “our,” “us” and “the company” are to EFH Corp. and/or its subsidiaries, TCEH and/or its subsidiaries, or Oncor and/or its subsidiary as apparent in the context. See “Glossary” for other defined terms.

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

See Note 15 for discussion of noncontrolling interests sold by Oncor in November 2008.

We have two reportable segments: the Competitive Electric segment, which is comprised principally of TCEH, and the Regulated Delivery segment, which is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary. See Note 24 for further information concerning reportable business segments.

Basis of Presentation

The consolidated financial statements have been prepared in accordance with US GAAP. The accompanying consolidated statements of income (loss), comprehensive income (loss), cash flows and equity present results of operations and cash flows for “Successor” and “Predecessor” periods, which relate to periods succeeding and preceding the Merger, respectively. The consolidated financial statements have been prepared on the same basis as the audited financial statements included in the 2008 Form 10-K. The consolidated financial statements of the Successor reflect the application of purchase accounting in accordance with the provisions of accounting standards related to business combinations, include the activities of Merger Sub, all of which related to the acquisition of EFH Corp., and reflect the adoption of accounting standards related to the determination of fair value. Certain reclassifications have been made to conform prior period data to current period presentation. 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. Subsequent events have been evaluated through February 18, 2010, the date these consolidated financial statements were issued.

Discontinued Businesses

Results from discontinued businesses, which are reported as 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 a 2005 TXU Europe litigation settlement agreement.

F-15

Use of Estimates

Preparation of financial statements requires 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 was accounted for under purchase accounting, whereby the total purchase price of the transaction was allocated to our 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

We enter into contracts for the purchase and sale of electricity, natural gas and other commodities and also enter 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 accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses, unless the criteria for certain exceptions are met, and an offsetting derivative asset or liability is recorded in the balance sheet. This recognition is referred to as “mark-to-market” accounting. The fair values of our unsettled derivative instruments under mark-to-market accounting are reported in the balance sheet as commodity and other derivative contractual assets or liabilities. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 16 and 18 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. Under the election criteria of accounting standards related to derivative instruments and hedging activities, we may elect the “normal” purchase and sale exemption. A commodity-related derivative contract may be designated as a “normal” purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.

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

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 12 and 18 for additional information concerning hedging activity.

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

Revenue Recognition

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

Our reported revenues include, on a net basis, ERCOT electricity balancing transactions, which represent wholesale purchases and sales of electricity for real-time balancing purposes as measured in 15-minute intervals. As is industry practice, these purchases and sales with ERCOT, as the balancing energy clearinghouse agent, are reported net in the income statement. Balancing transactions are difficult to predict, with results varying from period to period between net revenues and net expense, and are reported as a component of revenues in the income statement.

Impairment of Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 5 for details of the impairment of the natural gas-fueled generation facilities recorded in 2008.

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 for additional information.

Goodwill and Intangible Assets with Indefinite Lives

We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually. The impairment tests performed are based on discounted cash flow analyses. See Note 3 for details of goodwill and intangible assets with indefinite lives, including discussion of goodwill and trade name intangible assets impairments recorded in 2009 and 2008.

In 2009, we changed the annual test date for goodwill and intangible assets with indefinite lives from October 1 to December 1. Management determined the new annual goodwill test date is preferable because of efficiencies gained by aligning the test with our annual budget and five-year plan processes in the fourth quarter. The change in the annual test date did not delay, accelerate or avoid an impairment charge, and retrospective application of this change in accounting principle did not affect previously reported results.

Amortization of Nuclear Fuel

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

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Major Maintenance

Major maintenance costs incurred during generation plant outages and the costs of other maintenance activities are charged to expense as incurred and reported as operating costs.

Defined Benefit Pension Plans and Other Postretirement Employee Benefit Plans

We offer pension benefits based on either a traditional defined benefit formula or a cash balance formula and also offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from the company. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. The pension and OPEB accrued benefit obligations reported in the balance sheet are in accordance with accounting standards related to employers’ accounting for defined benefit pension and other postretirement plans. See Note 21 for additional information regarding pension and OPEB plans.

Stock-Based Incentive Compensation

Prior to the Merger, we provided discretionary awards payable in EFH Corp. common stock to qualified managerial employees under our shareholder-approved long-term incentive plans. In December 2007, our board of directors established our 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-based compensation expense is recognized over the vesting period based on the grant-date fair value of those awards. See Note 22 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 us by state and local government bodies, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates charged to customers by us are intended to recover the franchise and gross receipt taxes, but we are not acting as an agent to collect the taxes from customers.

Income Taxes

We file a consolidated federal income tax return, and federal income taxes are calculated for our subsidiaries substantially as if the entities file separate income tax returns. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities. Effective with the sale of noncontrolling interests in Oncor (see Note 15), Oncor became a partnership for US federal income tax purposes, and we provide deferred income taxes on the difference between the book and tax basis of our investment in Oncor. Previously earned investment tax credits were deferred and amortized as a reduction of income tax expense over the estimated lives of the related properties. In connection with purchase accounting, the remaining unamortized investment tax credit amount related to unregulated businesses of $300 million was eliminated. Investment tax credits related to Oncor’s regulated operations will continue to be amortized over the lives of the related properties in accordance with regulatory treatment. Certain provisions of the accounting guidance for income taxes 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.

Accounting for Contingencies

Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 13 for a discussion of contingencies.

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Cash and Cash Equivalents

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

We held an interest in The Reserve’s US Government Fund, which began liquidation proceedings in September 2008 due to the credit crisis and withdrawal demands. In September 2008, we attempted to redeem our interest, totaling $242 million, in the US Government Fund, but due to the liquidation process, the funds were not immediately made available; accordingly, such amount was reclassified from cash and cash equivalents to investment held in money market fund. We received $100 million of the funds in November 2008 and the remaining $142 million in January 2009.

Restricted Cash

The terms of certain agreements require the restriction of cash for specific purposes. At December 31, 2009, $1.135 billion of cash is restricted to support letters of credit. See Notes 12 and 25 for more details regarding this and other restricted cash.

Property, Plant and Equipment

As a result of purchase accounting, carrying amounts of property, plant and equipment related to unregulated businesses on the Merger date were adjusted to estimated fair values. Subsequent additions are recorded at cost. Regulated properties at Oncor continue to be reported at original cost, which is considered to be fair value due to the cost-based regulated recovery and 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 our 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 reflected blended estimates of the lives of major asset groups as compared to depreciation expense calculated on a component asset-by-asset basis. Effective with the Merger, depreciation expense for unregulated properties is calculated on a component asset-by-asset basis. Estimated depreciable lives are based on management’s estimates of the assets’ economic useful lives. See Note 25.

In accordance with the PUCT’s August 2009 order in Oncor’s rate review, the remaining net book value and anticipated removal cost of existing meters that are being replaced by advanced meters is being charged (amortized) to expense over an 11-year cost recovery period.

Capitalized Interest

Interest related to qualifying construction projects and qualifying software projects are capitalized in accordance with accounting guidance related to capitalization of interest cost. See Note 25.

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. Also see discussion immediately below regarding environmental allowances and credits.

Environmental Allowances and Credits

Effective with the Merger, we began accounting for all environmental allowances and credits as identifiable intangible assets with finite lives that are subject to amortization. The recorded values of these intangible assets were originally established reflecting fair value determinations as of the date of the Merger under purchase accounting. Amortization expense associated with these intangible assets is recognized on a unit of production basis as the allowances or credits are consumed in generation operations. The environmental allowances and credits are assessed for impairment when conditions or events occur that could affect the carrying value of the assets. See Note 3 for details of impairment amounts recorded in 2008.

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Regulatory Assets and Liabilities

The financial statements of our regulated electricity delivery operations reflect regulatory assets and liabilities under cost-based rate regulation in accordance with accounting standards related to the effect of certain types of regulation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 25 for details of the regulatory assets and liabilities.

Investments

Investments in a nuclear decommissioning trust fund are carried at fair market value in the balance sheet. Investments in unconsolidated business entities over which we have significant influence but do 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 19 for details of investments.

Noncontrolling Interests

See Note 15 for discussion of accounting for the noncontrolling interests of Oncor.

Changes in Accounting Standards

In January 2010, the FASB issued guidance on disclosure about fair value measurements. The guidance requires new disclosures of transfers in and out of Levels 1 and 2 of the fair value hierarchy and separate disclosure about purchases, sales, issuances and settlements in Level 3 of the fair value hierarchy. The guidance also provides clarification on disclosures related to the level of disaggregation among assets and liabilities and to the inputs and valuation techniques used to measure fair value. This new guidance is effective for periods beginning January 1, 2010, except for the new disclosures about purchases, sales, issuances and settlements in Level 3, which are effective for periods beginning January 1, 2011. As this new guidance provides only disclosure requirements, the adoption will not have any effect on reported results of operations, financial condition or cash flows.

In August 2009, the FASB issued guidance on measuring fair value of liabilities, which provides clarification of fair value measurement when there is limited or no observable data available. The adoption of this guidance, as of October 1, 2009, did not have any effect on reported results of operations, financial condition or cash flows, and did not have any effect on the disclosures of the fair value of our debt provided in Note 17.

In June 2009, the FASB issued “The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles,” which establishes the FASB Accounting Standards Codification™ (Codification) as the source of authoritative US GAAP recognized by the FASB to be applied to nongovernmental entities. The Codification was effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of the Codification did not affect reported results of operations, financial condition or cash flows.

In June 2009, the FASB issued new guidance that requires reconsideration of consolidation conclusions for all variable interest entities and other entities with which we are involved. This new guidance is effective January 1, 2010. The provisions of this guidance could result in different consolidation conclusions than reached under previous guidance, as the emphasis is on the power to direct the activities of the variable interest entity instead of risk and reward. We continue to evaluate the impact of this new guidance on our financial statements. In consideration of the ring-fencing measures in place, as discussed above under “Description of Business,” our evaluation may result in the deconsolidation of Oncor Holdings and its subsidiaries, which are the ring-fenced entities.

In June 2009, the FASB issued new guidance regarding accounting for transfers of financial assets that eliminates the concept of a qualifying special purpose entity, changes the requirements for derecognizing financial assets and requires additional disclosures. This new guidance is effective in the first quarter of 2010. We continue to evaluate the impact of this new guidance on our financial statements and footnote disclosures; however, we expect that our accounts receivable securitization program discussed in Note 11 will no longer be accounted for as a sale of accounts receivable as a result of the guidance, and the funding under the program will be reported as short-term borrowings. We do not expect this new guidance to impact the covenant-related ratio calculations in our debt agreements.

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In May 2009, the FASB issued new guidance related to subsequent events that requires disclosure of the date through which we have evaluated subsequent events related to the financial statements being issued and the basis for that date. Our adoption of this guidance as of April 1, 2009 did not affect reported results of operations, financial condition or cash flows, and the required disclosure is provided above in “Basis of Presentation.”

In April 2009, the FASB issued new guidance regarding determining fair value when the volume and level of activity for the asset or liability have significantly decreased or market transactions are not orderly. We adopted this guidance as of April 1, 2009. While this guidance did not change our fair value measurement techniques, it requires disclosures of additional detail of securities held in our nuclear decommissioning trust that are provided in Notes 16 and 19.

In April 2009, the FASB issued new guidance regarding the recognition and presentation of other-than-temporary impairments, which changed the guidance for recording impairment of investments in debt securities. Our adoption as of April 1, 2009 did not affect the accounting for our nuclear decommissioning trust fund because the trust balance has historically been reported at fair value, with changes in fair value of the trust resulting in changes in Oncor’s regulatory asset or liability related to the decommissioning cost.

In December 2008, the FASB issued new guidance for employers’ disclosures about postretirement benefit plan assets. This new guidance provides enhanced disclosures regarding how investment allocation decisions are made and certain aspects of fair value measurements on plan assets. The required disclosures are intended to provide transparency related to the types of assets and associated risks in an employer’s defined benefit pension or other postretirement employee benefits plan and events in the economy and markets that could have a significant effect on the value of plan assets. As this new guidance provides only disclosure requirements, our adoption as of December 31, 2009 did not have any effect on reported results of operations, financial condition or cash flows. The disclosures are provided in Note 21.

In March 2008, the FASB issued amended disclosure guidance for derivative instruments and hedging activities. This amended guidance 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. As this guidance provides only disclosure requirements, our adoption as of January 1, 2009 did not have any effect on reported results of operations or financial condition. The disclosures are provided in Note 18.

2. FINANCIAL STATEMENT EFFECTS OF THE MERGER

As discussed in Note 1, the Merger was completed on October 10, 2007. The aggregate purchase price paid for the equity securities of EFH Corp. was $31.9 billion, which was financed by a combination of equity invested by the Sponsor Group and certain other investors and by borrowings under a senior secured credit facility and senior unsecured interim facilities. These facilities also funded the repayment and redemption of certain existing credit facilities and debt upon completion of the Merger. See Note 12 for a discussion of our 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:			Use of funds:
			(billions of dollars)
Cash and other sources	$	0.3	Equity purchase price (c)	$	31.9
TCEH credit facilities (Note 12)		27.0	Transaction costs (d)		0.8
EFH Corp. senior unsecured interim facility (a)		4.5	Repayment of existing debt		5.3
Equity contributions (b)		8.3	Restricted cash		1.2
			Financing fees related to new facilities		0.9
Total source of funds	$	40.1	Total uses of funds	$	40.1

(a) Interim facility that was repaid with the proceeds from the issuance of the EFH Corp. Senior Notes that are discussed in Note 12.

(b) Consists of equity contributions by the Sponsor Group and certain other investors.

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(c) Represents 461.2 million outstanding shares of EFH Corp. common stock multiplied by $69.25 per share.

(d) 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

We accounted for the Merger under purchase accounting in accordance with the provisions of accounting standards related to business combinations, whereby the total purchase price of the transaction was allocated to our identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of the Merger date 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 us, our industry and the competitive wholesale power market that include forward natural gas price curves and market heat rates, retail customer attrition rates, generation plant operating and construction costs, and the effect on generation facility values of lignite fuel reserves and mining capabilities using currently available information. As a result of cost-based regulatory rate-setting processes, the book value of the majority of Oncor’s assets and liabilities effectively represent fair value, and no adjustments to those regulated assets or liabilities were recorded. The excess of the purchase price over the fair value of net assets acquired was recorded as goodwill.

The goodwill amount recorded upon finalization of purchase accounting in 2008 totaled $23.2 billion. Management believes the drivers of the goodwill amount include the incremental value of the future cash flow potential of the baseload generation facilities, including facilities under construction, over the values assigned to those assets under purchase accounting rules, considering the market-pricing mechanisms and growth potential in the ERCOT market, as well as the value derived from the scale of the retail business. Management also believes that the goodwill reflects the value of the relatively stable, long-lived cash flows of the regulated business, considering the constructive regulatory environment and market growth potential. See Note 3 for disclosures related to goodwill, including an impairment recorded in the fourth quarter of 2008 and first quarter of 2009.

The following table summarizes the components of the final purchase price allocation:

Equity purchase price		$	31,935
Transaction costs			759
Total purchase price			32,694
Property, plant and equipment	28,088
Intangible assets (Note 3)	4,454
Regulatory assets and deferred debits	1,445
Other assets	5,187
Total assets acquired	39,174
Short-term borrowings and long-term debt	14,183
Deferred tax liabilities	7,706
Other liabilities	7,837
Total liabilities assumed	29,726
Net identifiable assets acquired			9,448
Goodwill		$	23,246

The following table summarizes the change in the total amount of goodwill during 2008 as a result of purchase accounting:

Goodwill at December 31, 2007			$	22,954
Property, plant and equipment	311
Intangible assets	30
Regulatory assets — net	2
Other assets	174
Total assets acquired	517
Deferred income tax liabilities	(263	)
Other liabilities	38
Total liabilities assumed	(225	)
Net identifiable assets acquired				292
Goodwill at completion of purchase accounting			$	23,246

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The above changes relate largely to finalization of fair values of natural gas-fueled generation plants and amounts related to the Capgemini outsourcing agreement, as well as the effects on related deferred income tax balances.

Accrued liabilities were recorded in purchase accounting for exit activities resulting from the Merger. Exit liabilities recorded related to the cancellation of the development of coal-fueled generation facilities discussed in Note 4, the exit of certain administrative activities and the termination of outsourcing arrangements with Capgemini under change of control provisions of such arrangements (see Note 20). The following table summarizes the changes to the exit liability:

	Competitive Electric segment			Regulated Delivery segment			Total
Liability for exit activities as of October 11, 2007	$	60		$	—		$	60
Liability for exit activities as of December 31, 2007		60			—			60
Additions to liability (a)		38			16			54
Payments recorded against liability		(60	)		—			(60	)
Liability for exit activities as of December 31, 2008		38			16			54
Payments recorded against liability		(24	)		(4	)		(28	)
Other adjustments to the liability (b)		(11	)		(10	)		(21	)
Liability for exit activities as of December 31, 2009 (c)	$	3		$	2		$	5

(a) Additional amounts recorded upon finalization of purchase accounting.

(b) Represents reversal of exit liabilities due primarily to a shorter than expected outsourcing services transition period.

(c) Remaining accrual is expected to be settled in 2010, the targeted date to complete the transition of outsourced activities back to us or to service providers.

Unaudited Pro Forma Financial Information

The following unaudited pro forma financial position and results of operations assume that the Merger-related transactions occurred on January 1, 2007. The unaudited pro forma information is provided for informational purposes only and is not necessarily indicative of what our results of operations would have been if the Merger-related transactions had occurred on that date, or what our results of operations will be for any future periods.

For the year ended December 31, 2007, unaudited pro forma revenues and net loss were $10.0 billion and $2.3 billion, respectively. Pro forma adjustments for the year ended December 31, 2007 consist of adjustments for the Predecessor period and consist of $473 million in depreciation and amortization expense (including amounts recognized in revenues or fuel and purchased power costs), $2.1 billion in interest expense and a $895 million income tax benefit.

3. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

As discussed in Note 2, we accounted for the Merger under purchase accounting. The total goodwill amount recorded as a result of purchase accounting totaled $23.2 billion, representing the excess of the purchase price over the fair value of the tangible and identifiable intangible net assets acquired in the Merger; subsequently, impairment charges were recorded in the fourth quarter of 2008 and the first quarter of 2009 (discussed immediately below). Accounting guidance related to goodwill and other intangible assets 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 original goodwill amounts assigned to the Competitive Electric segment of $18.3 billion and the Regulated Delivery segment of $4.9 billion were based on the enterprise values of those businesses at the closing date of the Merger and the completion of purchase accounting.

Reported goodwill as of December 31, 2009 totaled $14.3 billion, with $10.2 billion assigned to the Competitive Electric segment and $4.1 billion to the Regulated Delivery segment. Reported goodwill as of December 31, 2008 totaled $14.4 billion, with $10.3 billion assigned to the Competitive Electric segment and $4.1 billion to the Regulated Delivery segment. None of this goodwill balance is being deducted for tax purposes.

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Goodwill and Trade Name Intangible Asset Impairments

The 2009 annual impairment testing performed as of October 1, and December 1, 2009 for goodwill and intangible assets with indefinite useful lives in accordance with accounting guidance for a change in annual impairment testing dates resulted in no impairment (see discussion in Note 1 regarding change in the annual impairment test date from October 1 to December 1). The goodwill testing determined that the estimated fair value (enterprise value) of the Regulated Delivery segment exceeded its carrying value by approximately 10% resulting in no additional testing being required and no impairment for the segment. Key assumptions in the valuation of the regulated business include discount rates, growth of the rate base and return on equity allowed by the regulatory authority. Cash flows of the regulated business are relatively stable and more predictable than the competitive business. The Competitive Electric segment carrying value exceeded its estimated enterprise value (by less than 10%), so the estimated enterprise value of the segment was compared to the estimated fair values of its operating assets and liabilities. This additional testing indicated that the implied goodwill amount exceeded the recorded goodwill amount, and thus no goodwill impairment was recorded. The estimated enterprise value of the Competitive Electric segment reflects the impact of the decline in forward natural gas prices on wholesale electricity prices. Because lower wholesale electricity prices also result in lower fair values of our generation assets, calculated implied goodwill was sufficient to support the recorded goodwill amount. Key variables in the tests included forward natural gas prices, electricity prices, market heat rates and discount rates, assumptions regarding each of which could have a significant effect on valuations. Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.

In the first quarter of 2009, we recorded a $90 million goodwill impairment charge largely related to the Competitive Electric segment. This charge resulted from the completion of fair value calculations supporting the initial $8.860 billion goodwill impairment charge that was recorded in the fourth quarter of 2008 and consisted of an impairment of $8.0 billion related to the Competitive Electric segment and $860 million related to the Regulated Delivery segment. The impairment charge primarily reflected the dislocation in the capital markets during the fourth quarter of 2008 that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies. The impairment determination involved significant assumptions and judgments in estimating enterprise values of the Competitive Electric and Regulated Delivery segments and the fair values of their assets and liabilities. This cumulative $8.950 billion charge is the only goodwill impairment recorded since the Merger.

Also in the fourth quarter of 2008, we recorded a trade name intangible asset impairment charge totaling $481 million ($310 million after-tax). The impairment primarily arises from the increase in the discount rate used in estimating fair value as discussed above.

Although the annual impairment test date for goodwill and intangible assets with indefinite lives set by management was October 1, management determined that in consideration of the continuing deterioration of securities values during the fourth quarter of 2008, an impairment testing trigger occurred subsequent to that test date; consequently, the impairment charges were based on estimated fair values at December 31, 2008. See Note 1 for discussion of the change of the annual impairment test date to December 1 in 2009.

The calculations supporting the impairment determination utilized models that took into consideration multiple inputs, including commodity prices, debt yields, equity prices of comparable companies and other inputs. Those models were generally used in developing long-term forward price curves for certain commodities and discount rates for determining fair values of our reporting units as well as certain individual assets and liabilities of those businesses. The fair value measurements resulting from such models are classified as Level 3 non-recurring fair value measurements consistent with accounting standards related to the determination of fair value (see Note 16).

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Identifiable Intangible Assets

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

	Successor
	As of December 31, 2009						As of December 31, 2008
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	215	$	248	$	463	$	130	$	333
Favorable purchase and sales contracts		700		374		326		700		249		451
Capitalized in-service software		490		167		323		255		116		139
Environmental allowances and credits		992		212		780		994		121		873
Land easements		188		72		116		184		69		115
Mining development costs		32		5		27		19		2		17
Total intangible assets subject to amortization	$	2,865	$	1,045		1,820	$	2,615	$	687		1,928
Trade name (not subject to amortization)						955						955
Mineral interests (not currently subject to amortization)						101						110
Total intangible assets					$	2,876					$	2,993

Details of amortization expense related to intangible assets (including income statement line item in which the amortization is included) follows:

		Successor								Predecessor
Intangible Asset (Income Statement line)	Segment	Useful lives at December 31, 2009 (weighted average in years)		Year Ended December 31, 2009		Year Ended December 31, 2008		Period from October 11, 2007 through December 31, 2007		Period from January 1, 2007 through October 10, 2007
Retail customer relationship (Depreciation and amortization)	Competitive Electric		4	$	85	$	51	$	79	$	—
Favorable purchase and sales contracts (Operating revenues/ fuel, purchased power costs and delivery fees)	Competitive Electric		12		125		168		72		—
Capitalized in-service software (Depreciation and amortization)	All		5		53		44		8		23
Environmental allowances and credits (Fuel, purchased power costs and delivery fees)	Competitive Electric		28		91		102		20		—
Land easements (Depreciation and amortization)	Regulated Delivery		67		3		3		—		2
Mining development costs (Depreciation and amortization)	Competitive Electric		5		3		1		—		—
Total amortization expense				$	360	$	369	$	179	$	25

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

• Retail Customer Relationship — Retail customer relationship intangible asset represents the estimated fair value of the non-contracted customer base and is being amortized using an accelerated method based on customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life.

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• Favorable Purchase and Sales Contracts — Favorable purchase and sales contracts intangible asset primarily represents the above market value, based on observable prices or estimates, of commodity contracts for which: (i) we have made the “normal” purchase or sale election allowed by accounting standards related to derivative instruments and hedging transactions or (ii) the contracts did not meet the definition of a derivative. The amortization periods of these intangible assets are based on the terms of the contracts. Unfavorable purchase and sales contracts are recorded as other noncurrent liabilities and deferred credits (see Note 25).

• Trade name — The trade name intangible asset represents the estimated fair value of the TXU Energy trade name, and was determined to be an indefinite-lived asset not subject to amortization. This intangible asset will be evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other intangible assets. See above for discussion of an impairment charge recorded in 2008.

• Environmental Allowances and Credits — This intangible asset represents the fair value, based on observable prices or estimates, of environmental credits, substantially all of which were expected to be used in our power generation activities. These credits are amortized utilizing a units-of-production method.

Impairment of Environmental Allowances and Credits Intangible Assets

In March 2005, the EPA issued regulations called the Clean Air Interstate Rule (CAIR) for 28 states, including Texas, where our generation facilities are located. CAIR requires reductions of SO2 and NOx emissions from power generation facilities in these 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.

Based on the D.C. Circuit Court’s ruling, we recorded a noncash impairment charge to earnings in 2008. We 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, NOx allowances would no longer be needed, and thus there would not be an actively traded market for such allowances. Consequently, our NOx allowances 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, we impaired SO 2 allowances in the amount of $100 million (before deferred income tax benefit). While the D.C. Circuit Court did not invalidate the Acid Rain Program, we would have more SO2 allowances than we would need to comply with the Acid Rain Program. While there continued to be a market for SO2 allowances, the D.C. Circuit Court’s decision resulted in a material decrease in the market price of SO2 allowances.

The impairment amounts recorded in 2008 were reported in other deductions and reflected in the results of the Competitive Electric segment.

In December 2008, in response to an EPA petition, the D.C. Circuit Court reversed, in part, its previous ruling. Such reversal confirmed CAIR is not valid, but allowed it to remain in place while the EPA revises CAIR to correct the previously identified shortcomings. Since the D.C. Circuit Court did not prescribe a deadline for this revision, at this time, we cannot predict how or when the EPA may revise CAIR.

Estimated Amortization of Intangible Assets — The estimated aggregate amortization expense of intangible assets for each of the next five fiscal years is as follows:

Year	Amortization Expense
2010	$	278
2011		210
2012		166
2013		147
2014		133

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4. CHARGES RELATED TO CANCELLED DEVELOPMENT OF COAL-FUELED GENERATION FACILITIES

In 2007, we recorded a net charge totaling $757 million ($492 million after-tax), substantially all of which was in the Predecessor period, in connection with the February 2007 suspension of the development of eight coal-fueled generation units. This decision and subsequent terminations of equipment orders required an evaluation of the recoverability of recorded assets associated with the development program. The net charge included $705 million for the impairment of construction work-in-process asset balances (primarily pre-construction development costs), $79 million for costs arising from terminations of equipment orders, $29 million for the write-off of deferred financing costs and a $57 million gain on sale (in early October 2007) of two in-process boilers. Additional charges totaling $12 million ($8 million after-tax) were recorded in 2008, which primarily represented costs for transportation and storage of materials.

The construction work-in-process asset balances totaled $871 million prior to the writedown and included progress payments made and accruals for amounts due to equipment suppliers, based on percentage of completion estimates, engineering and design services costs, site preparation expenditures, internal salary and related overhead costs for personnel engaged directly in construction management activities and capitalized interest. The remaining carrying value of assets related to the program at December 31, 2009 totaled $77 million and represented estimated recovery amounts, using a probability-weighted methodology, from equipment salvage and potential resale activities. Cumulative net cash proceeds through December 31, 2009 from the sale of the impaired assets totaled $172 million.

We have terminated all of the equipment orders, with the exception of one purchase order for a boiler that we are attempting to sell, 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.

5. IMPAIRMENT OF NATURAL GAS-FUELED GENERATION FACILITIES

In 2008, we performed an evaluation of our natural gas-fueled generation facilities for impairment. The impairment test was triggered by a determination that it was more likely than not that certain generation units would be retired or mothballed (idled) earlier than previously expected. The natural gas-fueled generation units are generally operated to meet peak demands for electricity and all such facilities are tested for impairment as an asset group. As a result of the evaluation, it was determined that an impairment existed, and a charge of $229 million ($147 million after-tax) was recorded to write down the assets to fair value of approximately $28 million, which was determined based on discounted estimated future cash flows. The impairment was reported in other deductions in the Competitive Electric segment.

6. STIPULATION APPROVED BY THE PUCT

Oncor and Texas Holdings agreed to the terms of a stipulation, which was conditional upon completion of the Merger, with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. In February 2008, the PUCT entered an order approving the stipulation. The PUCT issued a final order on rehearing in April 2008 that has been appealed to 200th District Court of Travis County, Texas. The parties to the appeal have agreed to a schedule that would result in a hearing in June 2010.

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

• Oncor provided a one-time $72 million refund to its REP customers in the September 2008 billing cycle. The refund was in the form of a credit on distribution fee billings. The liability for the refund was recorded as part of purchase accounting.

• Consistent with the 2006 cities rate settlement (see Note 7), Oncor filed a system-wide rate case in June 2008 based on a test-year ended December 31, 2007. In August 2009, the PUCT issued a final order on this rate case. See Note 25.

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• Oncor agreed not to request recovery of approximately $56 million of regulatory assets related to self-insurance reserve costs and 2002 restructuring expenses. These regulatory assets were eliminated as part of purchase accounting.

• The dividends paid by Oncor will be limited through December 31, 2012, to an amount not to exceed Oncor’s net income (determined in accordance with GAAP, subject to certain defined adjustments) for the period beginning October 11, 2007 and ending December 31, 2012, and are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.

• Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions.

• Oncor committed to an additional $100 million in spending over the five-year period ending December 31, 2012 on demand-side management or other energy efficiency initiatives. These additional expenditures will not be recoverable in rates, and this amount was recorded as a regulatory liability as part of purchase accounting and consistent with accounting standards related to the effect of certain types of regulation.

• If Oncor’s credit rating is below investment grade with two or more rating agencies, TCEH will post a letter of credit in an amount of $170 million to secure TXU Energy’s payment obligations to Oncor.

• Oncor agreed not to request recovery of the $4.9 billion of goodwill resulting from purchase accounting or any future impairment of the goodwill in its rates.

7. CITIES RATE SETTLEMENT IN 2006

In January 2006, Oncor agreed with a steering committee representing 108 cities in Texas (Cities) to defer the filing of a system-wide rate case with the PUCT to no later than July 1, 2008 (based on a test year ending December 31, 2007). Oncor filed the rate case with the PUCT in June 2008, and the PUCT issued a final order on the case in 2009. Oncor extended the benefits of the agreement to 292 nonlitigant cities. The agreements provided that Oncor would make payments to participating cities totaling approximately $70 million, including incremental franchise taxes.

This amount was recognized in earnings over the period from May 2006 through June 2008. Amounts recognized totaled $11 million in 2009, $23 million in 2008, $8 million for the period October 11, 2007 through December 31, 2007 and $25 million for the period January 1, 2007 through October 10, 2007, of which $2 million, $13 million, $6 million and $20 million, respectively, were reported in other deductions (see Note 10), with the remainder reported in franchise and revenue-based taxes. Amounts recognized in 2009 represented extension of benefits per the agreement related to the timing of completion of the rate case.

8. ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES

Effective January 1, 2007, we adopted accounting guidance related to uncertain tax positions. This guidance requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable. We applied updated guidance to determine if each tax position was effectively settled for the purpose of recognizing previously uncertain tax positions. We completed our review and assessment of uncertain tax positions and in the 2007 Predecessor period recorded a net benefit to retained earnings and a decrease to noncurrent liabilities of $33 million in accordance with the new accounting rule.

We 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 our income tax returns for the years ending prior to January 1, 2003 are complete, but the tax years 1997 to 2002 remain in appeals with the IRS. The conclusion of issues contested from the 1997 to 2002 audit, including matters related to TXU Europe, is not expected to occur prior to 2011. In 2008, we were notified of the commencement of an IRS audit of tax years 2003 to 2006. The audit is expected to require two years to complete. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginning after 2002.

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In 2008, we participated in negotiations with the IRS regarding the 2002 worthlessness loss associated with our discontinued Europe business, and we reduced the liability for uncertain tax positions in accordance with accounting guidance. The reduction in the liability of approximately $375 million was largely offset by a reduction of deferred tax assets related to alternative minimum tax.

We classify interest and penalties related to uncertain tax positions as current income tax expense. Amounts recorded related to interest and penalties totaled $42 million in 2009, $88 million in 2008, including $29 million recorded as goodwill, $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 (all amounts after tax).

Noncurrent liabilities included a total of $361 million and $198 million in accrued interest at December 31, 2009 and 2008, respectively. Effective in 2009, the federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferred income taxes. Such amounts were previously reported net as a reduction of the liability for uncertain tax positions.

The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in the consolidated balance sheet, during the years ended December 31, 2009 and 2008:

	2009			2008
Balance at January 1, excluding interest and penalties	$	1,583		$	1,834
Additions based on tax positions related to prior years		71			124
Reductions based on tax positions related to prior years		(82	)		(451	)
Additions based on tax positions related to the current year		66			33
Settlements with taxing authorities		—			43
Reductions related to the lapse of the tax statute of limitations		—			—
Balance at December 31, excluding interest and penalties	$	1,638		$	1,583

Of the balance at December 31, 2009, $1.474 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 we sustain such positions on income tax returns previously filed, liabilities recorded would be reduced by $164 million, resulting in increased income from continuing operations and a favorable impact on the effective tax rate.

We filed a claim in 2006 for refund of income taxes and related interest paid in 2005 associated with IRS audits of 1993 and 1994 tax returns of a discontinued operation. The expected refund was recognized in the adoption of accounting guidance related to uncertain tax positions. We received the refund, totaling $98 million, in February 2009.

We do not expect the total amount of liabilities recorded related to uncertain tax positions will significantly increase or decrease within the next 12 months.

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9. INCOME TAXES

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

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Current:
US Federal	$	64		$	(46	)	$	52		$	400
State		51			52			10			20
Total		115			6			62			420
Deferred:
US Federal		256			(482	)		(722	)		12
State		1			10			(12	)		(108	)
Total		257			(472	)		(734	)		(96	)
Amortization of investment tax credits		(5	)		(5	)		(1	)		(15	)
Total	$	367		$	(471	)	$	(673	)	$	309

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

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1,  2007 through October 10, 2007
Income (loss) from continuing operations before income taxes	$	775		$	(10,469	)	$	(2,034	)	$	1,008
Income taxes at the US federal statutory rate of 35%	$	271		$	(3,664	)	$	(712	)	$	353
Nondeductible goodwill impairment		32			3,101			—			—
Lignite depletion allowance		(18	)		(29	)		(5	)		(30	)
Production activities deduction		—			—			10			(10	)
Amortization of investment tax credits — net of deferred income tax effect		(5	)		(5	)		(1	)		(12	)
Amortization (under regulatory accounting) of statutory rate changes		5			2			—			2
Medicare subsidy — other postretirement employee benefits		(7	)		(6	)		(2	)		(6	)
Nondeductible interest expense		13			11			1			—
Nondeductible losses (earnings) on benefit plans		(1	)		9			(1	)		(6	)
Texas margin tax, net of federal tax benefit		30			39			(3	)		16
Texas margin tax — deferred tax adjustment		—			—			—			(70	)
Nondeductible merger transaction costs		—			—			23			—
Deferred tax adjustments		—			—			—			25
Accrual of interest, net of federal tax benefit		42			59			12			43
Other, including audit settlements		5			12			5			4
Income tax expense (benefit)	$	367		$	(471	)	$	(673	)	$	309
Effective tax rate		47.4	%		4.5	%		33.1	%		30.7	%

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 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, we recorded a deferred tax benefit of $70 million, essentially all of which related to changes in the rate at which a tax credit is calculated as specified in the new law. Of the total $70 million deferred tax benefit, $32 million was recognized in the Competitive Electric segment results and $38 million was recognized in the Corporate and Other nonsegment results.

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Deferred Income Tax Balances

Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2009 and 2008 balance sheet dates are as follows:

	Successor
	December 31, 2009							December 31, 2008
	Total		Current			Noncurrent		Total		Current			Noncurrent
Deferred Income Tax Assets
Alternative minimum tax credit carryforwards	$	438	$	—		$	438	$	447	$	—		$	447
Employee benefit liabilities		206		22			184		173		33			140
Net operating loss (NOL) carryforwards		422		—			422		523		—			523
Unfavorable purchase and sales contracts		249		—			249		259		—			259
Accrued interest		211		—			211		—		—			—
Other		351		13			338		260		44			216
Total		1,877		35			1,842		1,662		77			1,585
Deferred Income Tax Liabilities
Property, plant and equipment		4,141		—			4,141		4,375		—			4,375
Basis difference in Oncor partnership (a)		1,369		—			1,369		1,333		—			1,333
Commodity contracts and interest rate swaps		1,325		30			1,295		645		31			614
Identifiable intangible assets		921		—			921		1,049		—			1,049
Debt fair value discounts		184		—			184		257		—			257
Other		63		—			63		26		2			24
Total		8,003		30			7,973		7,685		33			7,652
Net Deferred Income Tax (Asset) Liability	$	6,126	$	(5	)	$	6,131	$	6,023	$	(44	)	$	6,067

(a) See Note 14.

At December 31, 2009 we had $438 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, 2009, we had net operating loss (NOL) carryforwards for federal income tax purposes of $1.206 billion that expire between 2023 and 2028. The NOL carryforwards can be used to offset future taxable income. We expect to utilize all of our NOL carryforwards prior to their expiration dates.

The component of deferred income tax liabilities referred to as “basis difference in Oncor partnership” arose as a result of the sale of noncontrolling interests in Oncor (see Note 15) at which time Oncor became a partnership for US federal income tax purposes. The amount of this basis difference at the date of the transaction represented our interest (approximately 80%) in the net deferred tax liabilities related to Oncor’s individual operating assets and liabilities. The remaining net deferred tax liabilities associated with Oncor ($321 million at December 31, 2009) that are attributable to the noncontrolling interests have been reclassified as other noncurrent liabilities (see Note 25).

The income tax effects of the components included in accumulated other comprehensive income at December 31, 2009 and 2008 totaled a net deferred tax asset of $165 million and $207 million, respectively.

See Note 8 for discussion regarding accounting for uncertain tax positions.

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10. OTHER INCOME AND DEDUCTIONS

	Successor						Predecessor
	Year Ended December 31, 2009		Year Ended December 31, 2008		Period from October 11, 2007 through December 31, 2007		Period from January 1,  2007 through October 10, 2007
Other income:
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting (Note 25)	$	39	$	44	$	10	$	—
Amortization of gain on sale of TXU Fuel (a)		—		—		—		36
Debt extinguishment gain (Note 12)		87		—		—		—
Reversal of reserves recorded in purchase accounting (b)		44		—		—		—
Fee received related to interest rate swap/commodity hedge derivative agreement (c) (Note 18)		6		—		—		—
Insurance recoveries (d)		—		21		—		—
Net gain on sale of other properties and investments		4		4		1		4
Reduction of insurance reserves related to discontinued operations		—		—		1		7
Penalty received for nonperformance under a coal transportation agreement		—		—		—		6
Mineral rights royalty income		6		4		1		8
Other		18		7		1		8
Total other income	$	204	$	80	$	14	$	69
Other deductions:
Impairment of trade name intangible asset (Note 3)	$	—	$	481	$	—	$	—
Impairment of emission allowances intangible assets (Note 3)		—		501		—		—
Charge for impairment of natural gas-fueled generation facilities (Note 5)		—		229		—		—
Impairment of land (e)		34		—		—		—
Charge related to Lehman bankruptcy (f)		—		26		—		—
Write-off of regulatory assets (Note 25)		25		—		—		—
Professional fees incurred related to the Merger (g)		—		14		51		39
Net charges related to cancelled development of generation facilities (Note 4)		6		12		2		755
Severance charges		7		—		—		—
Charge related to termination of rail car lease (h)		—		—		—		10
Other asset writeoffs (i)		5		2		—		34
Credit related to impaired leases (j)		—		—		—		(48	)
Costs related to 2006 cities rate settlement (Note 7)		2		13		6		20
Litigation/regulatory settlements		3		10		—		5
Expenses related to cancelled joint venture at Oncor		—		—		—		12
Other		15		13		2		14
Total other deductions	$	97	$	1,301	$	61	$	841

(a) As part of the 2004 sale of the assets of TXU Fuel, TCEH entered into a transportation agreement with the new owner, intended to be market-price based, to transport natural gas to TCEH’s generation plants. Because of the continuing involvement in the business through the transportation agreement, the pretax gain of $375 million related to the sale was deferred and being recognized over the eight-year life of the transportation agreement, and the business was not accounted for as a discontinued operation. The remaining $218 million deferred gain was eliminated as part of purchase accounting related to the Merger. Reported in Corporate and Other activities.

(b) Includes $23 million for reversal of a use tax accrual, related to periods prior to the Merger, due to a state ruling in 2009 (reported in Competitive Electric segment) and $21 million for reversal of excess exit liabilities recorded in connection with the termination of outsourcing arrangements (see Notes 2 and 20) (reported in Competitive Electric ($11 million) and Regulated Delivery segments ($10 million)).

(c) Reported in Competitive Electric segment.

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(d) Represents insurance recovery for damage to mining equipment. Reported in Competitive Electric segment.

(e) Impairment of land expected to be sold in the next 12 months. Reported in Competitive Electric segment.

(f) Represents reserve established against amounts due (excluding termination related costs) from subsidiaries of Lehman Brothers Holdings Inc. (Lehman) arising from commodity hedging and trading activities. There are no open positions with these subsidiaries. Reported in Competitive Electric segment.

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

(h) Represents costs associated with termination and refinancing of a rail car lease. Reported in Competitive Electric segment.

(i) Predecessor period includes $30 million of previously deferred costs, consisting primarily of professional fees for tax, legal and other advisory services, in connection with certain previously anticipated strategic transactions (including expected financings) that were no longer expected to be consummated as a result of the Merger. Reported in Corporate and Other activities.

(j) In 2004, we recorded a charge of $157 million for leases of certain natural gas-fueled combustion turbines, net of estimated sublease revenues, that were no longer operated for our own benefit. In the third quarter of 2007, a $48 million reduction in the related liability was recorded to reflect new subleases entered into in October 2007 (reported in the Competitive Electric segment results). The remaining $59 million liability was eliminated as part of purchase accounting as we intend to operate these assets for our own benefit.

11. TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

TXU Energy participates in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with transfers and servicing accounting standards (see Note 1 for discussion of a new accounting standard effective in the first quarter of 2010). Under the program, TXU Energy (originator) sells trade accounts receivable to TXU Receivables Company, which is a special purpose entity created for the purpose of purchasing receivables from the originator and is a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp. TXU Receivables Company sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions (the funding entities). As discussed below, Oncor also participated in the program prior to the Merger.

The maximum amount currently available under the accounts receivable securitization program is $700 million, and program funding totaled $383 million at December 31, 2009. Under the terms of the program, available funding was reduced by the total of $83 million of customer deposits held by the originator at December 31, 2009 because TCEH’s credit ratings were lower than Ba3/BB-.

All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, reflect seasonal variations in the level of accounts receivable, changes in collection trends and other factors such as changes in sales prices and volumes. TXU Receivables Company has issued subordinated notes payable to the originator for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originator that was funded by the sale of the undivided interests. The balance of the subordinated notes payable, which is eliminated in consolidation, totaled $463 million and $268 million at December 31, 2009 and 2008, respectively.

The discount from face amount on the purchase of receivables from the originator principally funds program fees paid to the funding entities. The program fees, which are also referred to as losses on sale of the receivables under transfers and servicing accounting standards, consist primarily of interest costs on the underlying financing. The discount also funds a servicing fee paid by TXU Receivables Company to EFH Corporate Services Company (Service Co.), a direct wholly-owned subsidiary of EFH Corp., which provides recordkeeping services and is the collection agent for the program.

Program fee amounts, which are reported in SG&A expenses, were as follows:

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Program fees	$	12		$	25		$	9		$	32
Program fees as a percentage of average funding (annualized)		2.4	%		5.2	%		9.5	%		6.4	%

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The trade accounts receivable balance reported in the December 31, 2009 consolidated balance sheet includes $846 million face amount of retail trade accounts receivable sold net of proceeds from the sale of undivided interests in those receivables totaling $383 million. Funding under the program decreased $33 million in 2009, increased $53 million in 2008 and decreased $264 million in 2007. 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.

In connection with the Merger, the accounts receivable securitization program was amended. Concurrently with the amendment, the financial institutions required that Oncor repurchase all of the receivables it had previously sold to TXU Receivables Company, which totaled $254 million. Oncor funded such repurchases through borrowings under its credit facility of $113 million, and a related subordinated note receivable from TXU Receivables Company in the amount of $141 million was canceled. Amounts related to Oncor’s trade accounts receivable for the period from January 1, 2007 through October 10, 2007 totaled $6 million in program fees and $27 million in operating cash flows provided, exclusive of the $113 million used by Oncor to repurchase its receivables at the time of the Merger.

Activities of TXU Receivables Company were as follows:

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Cash collections on accounts receivable	$	6,125		$	6,393		$	1,538		$	6,251
Face amount of new receivables purchased		(6,287	)		(6,418	)		(1,194	)		(6,628	)
Discount from face amount of purchased receivables		14			29			9			35
Program fees paid to funding entities		(12	)		(25	)		(9	)		(32	)
Servicing fees paid to Service Co. for recordkeeping and collection services		(2	)		(4	)		(1	)		(3	)
Increase (decrease) in subordinated notes payable		195			(28	)		(120	)		305
Oncor’s repurchase of receivables previously sold		—			—			113			—
Operating cash flows used by (provided to) originators under the program	$	33		$	(53	)	$	336		$	(72	)

The program, which expires in October 2013, may be terminated upon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds, and the funding entities do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Receivables Company or the EFH Corp. subsidiary acting as collection agent defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities, or if TCEH, any affiliate of TCEH acting as collection agent other than the EFH Corp. subsidiary, any parent guarantor of the originator or the originator shall default in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. As of December 31, 2009, there were no such events of termination.

Upon termination of the program, liquidity would be reduced as collections of sold receivables would be used by TXU Receivables Company to repurchase the undivided interests from the funding entities instead of purchasing new receivables. 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 funding entities in the purchased receivables.

F-34

Trade Accounts Receivable

	Successor
	December 31,
	2009			2008
Gross wholesale and retail trade accounts receivable	$	1,726		$	1,705
Undivided interests in retail accounts receivable sold by TXU Receivables Company		(383	)		(416	)
Allowance for uncollectible accounts		(83	)		(70	)
Trade accounts receivable — reported in balance sheet	$	1,260		$	1,219

Gross trade accounts receivable at December 31, 2009 and 2008 included unbilled revenues of $546 million and $505 million, respectively.

Allowance for Uncollectible Accounts Receivable

Predecessor:
Allowance for uncollectible accounts receivable as of December 31, 2006	$	13
Increase for bad debt expense		46
Decrease for account write-offs		(54	)
Changes related to receivables sold		26
Allowance for uncollectible accounts receivable as of October 10, 2007		31
Successor:
Allowance for uncollectible accounts receivable as of October 11, 2007		31
Increase for bad debt expense		13
Decrease for account write-offs		(12	)
Allowance for uncollectible accounts receivable as of December 31, 2007		32
Increase for bad debt expense		81
Decrease for account write-offs		(69	)
Charge related to Lehman bankruptcy		26
Allowance for uncollectible accounts receivable as of December 31, 2008		70
Increase for bad debt expense		113
Decrease for account write-offs		(99	)
Other		(1	)
Allowance for uncollectible accounts receivable as of December 31, 2009	$	83

12. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

At December 31, 2009, we had outstanding short-term borrowings of $1.569 billion at a weighted average interest rate of 2.50%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $953 million for TCEH and $616 million for Oncor.

At December 31, 2008, we had outstanding short-term borrowings of $1.237 billion at a weighted average interest rate of 3.41%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $900 million for TCEH and $337 million for Oncor.

Credit Facilities

Our credit facilities with cash borrowing and/or letter of credit availability at December 31, 2009 are presented below. The facilities are all senior secured facilities of the authorized borrower.

		At December 31, 2009
Authorized Borrowers and Facility	Maturity Date	Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Revolving Credit Facility (a)	October 2013	$	2,700	$	—	$	953	$	1,721
TCEH Letter of Credit Facility (b)	October 2014		1,250		—		1,250		—
Subtotal TCEH (c)		$	3,950	$	—	$	2,203	$	1,721
TCEH Commodity Collateral Posting Facility (d)	December 2012		Unlimited	$	—		—		Unlimited
Oncor Revolving Credit Facility (e)	October 2013	$	2,000	$	—	$	616	$	1,262

F-35

(a) Facility used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount includes $141 million of commitments from Lehman that are only available from the fronting banks and the swingline lender and excludes $26 million of requested cash draws that have not been funded by Lehman. All outstanding borrowings under this facility at December 31, 2009 bear interest at LIBOR plus 3.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion of the facility.

(b) Facility used for issuing letters of credit for general corporate purposes, including, but not limited to, providing collateral support under hedging arrangements and other commodity transactions that are not eligible for funding under the TCEH Commodity Collateral Posting Facility. The borrowings under this facility were drawn at the inception of the facility, are classified as long-term debt, and except for $115 million related to a letter of credit drawn in June 2009, have been retained as restricted cash. Letters of credit totaling $736 million issued as of December 31, 2009 are supported by the restricted cash, and the remaining letter of credit availability totals $399 million.

(c) Pursuant to PUCT rules, TCEH is required to maintain available capacity under its credit facilities to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at December 31, 2009, the total availability under the TCEH credit facilities should be further reduced by $228 million.

(d) Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 600 million MMBtu as of December 31, 2009. As of December 31, 2009, there were no borrowings under this facility. See “TCEH Senior Secured Facilities” below for additional information.

(e) Facility used by Oncor for its general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount excludes $122 million of commitments from Lehman. All outstanding borrowings under this facility at December 31, 2009 bear interest at LIBOR plus 0.350%, and a facility fee is payable (currently at a rate per annum equal to 0.125%) on the commitments under the facility. The interest rate and facility fee rate per annum declined in June 2009 from LIBOR plus 0.425% and 0.150%, respectively, due to a two notch upgrade in Oncor’s credit ratings by Moody’s.

Long-Term Debt

At December 31, 2009 and 2008, the long-term debt consisted of the following:

	December 31, 2009			December 31, 2008
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			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			171
0.264% Floating Series 2001D-2 due May 1, 2033 (b)		97			97
0.317% Floating Taxable Series 2001I due December 1, 2036 (c)		62			62
0.264% 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
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)		(147	)		(161	)
Senior Secured Facilities:
3.743% TCEH Initial Term Loan Facility maturing October 10, 2014 (e)(f)		16,079			16,244
3.735% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (e)(f)		4,075			3,562

F-36

	December 31, 2009			December 31, 2008
3.731% TCEH Letter of Credit Facility maturing October 10, 2014 (f)		1,250			1,250
0.215% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (g)		—			—
Other:
10.25% Fixed Senior Notes due November 1, 2015 (h)		2,944			3,000
10.25% Fixed Senior Notes Series B due November 1, 2015 (h)		1,913			2,000
10.50 / 11.25% Senior Toggle Notes due November 1, 2016		1,952			1,750
7.000% Fixed Senior Notes due March 15, 2013		5			5
7.100% Promissory Note due January 5, 2009		—			65
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		55			67
Capital lease obligations		153			159
Unamortized fair value discount (d)		(4	)		(6	)
Total TCEH	$	29,810		$	29,470
EFC Holdings
9.580% Fixed Notes due in semiannual installments through December 4, 2019	$	51		$	55
8.254% Fixed Notes due in quarterly installments through December 31, 2021		50			53
1.081% 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)		(11	)		(12	)
Total EFC Holdings		99			105
EFH Corp. (parent entity)
10.875% Fixed Senior Notes due November 1, 2017		1,831			2,000
11.25 / 12.00% Senior Toggle Notes due November 1, 2017		2,797			2,500
9.75% Fixed Senior Secured Notes due October 15, 2019		115			—
4.800% Fixed Senior Notes Series O due November 15, 2009		—			3
5.550% Fixed Senior Notes Series P due November 15, 2014 (i)		983			1,000
6.500% Fixed Senior Notes Series Q due November 15, 2024 (i)		740			750
6.550% Fixed Senior Notes Series R due November 15, 2034 (i)		744			750
8.820% Building Financing due semiannually through February 11, 2022 (j)		75			80
Unamortized fair value premium related to Building Financing (d)		17			22
Unamortized fair value discount (d)		(599	)		(661	)
Total EFH Corp.		6,703			6,444
Intermediate Holding
9.75% Fixed Senior Secured Notes due October 15, 2019		141			—
Oncor (k)
6.375% Fixed Senior Notes due May 1, 2012		700			700
5.950% Fixed Senior Notes due September 1, 2013		650			650
6.375% Fixed Senior Notes due January 15, 2015		500			500
6.800% Fixed Senior Notes due September 1, 2018		550			550
7.000% Fixed Debentures due September 1, 2022		800			800
7.000% Fixed Senior Notes due May 1, 2032		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
7.500% Fixed Senior Notes due September 1, 2038		300			300
Unamortized discount		(15	)		(16	)
Total Oncor		4,335			4,334
Oncor Electric Delivery Transition Bond Company LLC (l)
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		13			54
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		130			130
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		145			145
3.520% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2009		—			39
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		197			221

F-37

	December 31, 2009			December 31, 2008
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		290			290
Total Oncor Electric Delivery Transition Bond Company LLC		775			879
Unamortized fair value discount related to transition bonds (d)		(6	)		(9	)
Total Oncor consolidated		5,104			5,204
Total EFH Corp. consolidated		41,857			41,223
Less amount due currently (m)		(417	)		(385	)
Total long-term debt	$	41,440		$	40,838

(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, 2009. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(c) Interest rate in effect at December 31, 2009. This series is in a weekly interest rate mode and is classified as long-term as it is supported by long-term irrevocable letters of credit.

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

(e) Interest rate swapped to fixed on $16.30 billion principal amount.

(f) Interest rates in effect at December 31, 2009.

(g) Interest rate in effect at December 31, 2009, excluding a quarterly maintenance fee of approximately $11 million. See “Credit Facilities” above for more information.

(h) 2009 amounts exclude $56 million and $87 million of the original and Series B notes, respectively, that are held by EFH Corp. and Intermediate Holding and eliminated in consolidation. See discussion of debt exchanges below.

(i) 2009 amounts exclude $9 million, $6 million and $3 million of the Series P, Series Q and Series R notes, respectively, that are held by Intermediate Holding and eliminated in consolidation. See discussion of debt exchanges below.

(j) This financing is secured and will be serviced with $115 million in restricted cash drawn in June 2009 by the beneficiary of a letter of credit. The issuer elected not to extend the expiration date of the letter of credit, and TCEH elected to allow the drawing in lieu of reissuing the letter of credit under the TCEH Revolving Credit Facility. The remaining $104 million of the prepayment (net of $11 million of debt service payments) is included in other current assets and other noncurrent assets on the balance sheet.

(k) Secured with first priority lien as discussed under “Oncor Secured Revolving Credit Facility” below.

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

(m) Includes zero and $3 million at December 31, 2009 and 2008, respectively, representing debt of the EFH Corp. parent entity.

EFH Corp. 10% Senior Secured Notes Issued in 2010 — In January 2010, EFH Corp. issued $500 million aggregate principal amount of 10.00% Senior Secured Notes due 2020 (the EFH Corp. 10% Notes). The notes will mature on January 15, 2020, and interest is payable in cash in arrears on January 15 and July 15 of each year at a fixed rate of 10.00% per annum with the first interest payment due on July 15, 2010. Other than interest rate and maturity date, the notes have the same guarantees and collateral and substantially the same other terms and conditions as the EFH Corp. 9.75% Notes.

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

The EFH Corp. 10% 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. 10% Notes (except for provisions relating to the transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the EFH Corp. 10% Notes. EFH Corp. has agreed to use commercially reasonable efforts to cause the exchange offer to be completed or, if required under special circumstances, to have one or more shelf registration statements declared effective, within 360 days after the issue date of the notes. If this obligation is not satisfied (a Registration Default), the annual interest rate on the notes will increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter the annual interest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues. If the Registration Default is cured, the interest rate on the notes will revert to the original level.

F-38

Debt-Related Activity in 2009 — Repayments of long-term debt in 2009 totaling $396 million represented principal payments at scheduled maturity dates as well as other repayments totaling $50 million, principally related to capitalized leases. Payments at scheduled amortization or maturity dates included $165 million repaid under the TCEH Initial Term Loan Facility, $104 million of Oncor transition bond principal payments, $65 million repaid under a TCEH promissory note, $9 million repaid under the TCEH Delayed Draw Term Loan Facility and $3 million of EFH Corp. senior notes.

Increases in long-term debt during 2009 totaling $522 million consisted of increased borrowings under the TCEH Delayed Draw Term Loan Facility, which was fully drawn as of July 2009, to fund expenditures related to construction of new generation facilities and environmental upgrades of existing lignite/coal-fueled generation facilities. In addition, long-term debt increased as a result of EFH Corp. increasing, through the payment-in-kind (PIK) election, the principal amount of its 11.25%/12.00% Senior Toggle Notes due November 2017 (EFH Corp. Toggle Notes) by $309 million and TCEH increasing, through the PIK election, the principal amount of its 10.50%/11.25% Senior Toggle Notes due November 2016 (TCEH Toggle Notes) by $202 million, in each case, in lieu of making cash interest payments.

Debt Exchanges — In October 2009, EFH Corp., Intermediate Holding and EFIH Finance, a wholly-owned subsidiary of Intermediate Holding, commenced offers to exchange up to approximately $4.9 billion principal amount of EFH Corp. 10.875% Senior Notes due November 2017 (EFH Corp. 10.875% Notes) and EFH Corp. Toggle Notes (collectively with the EFH Corp. 10.875% Notes, the EFH Corp. Senior Notes), EFH Corp. Series P, Q and R Notes and TCEH 10.25% Notes due November 2015 (the TCEH 10.25% Notes and collectively, with the EFH Corp. 10.875% Notes, Toggle Notes and Series P, Q and R Notes, the Old Notes) for up to $3.0 billion of new senior secured notes, with up to $1.35 billion to be issued by EFH Corp. and up to $1.65 billion to be issued by Intermediate Holding and EFIH Finance (the EFIH Co-Issuers). The purpose of the debt exchanges was to reduce the outstanding principal amount and extend the weighted average maturity of our long-term debt.

The debt exchange transactions, which closed in November 2009, resulted in the tendering of $357 million principal amount of Old Notes in exchange for $115 million principal amount of 9.75% Senior Secured Notes issued by EFH Corp. (the EFH Corp. 9.75% Notes) and $141 million principal amount of 9.75% Senior Secured Notes issued by Intermediate Holding and EFIH Finance (the EFIH Notes). The EFH Corp. 9.75% Notes and EFIH Notes will mature in October 2019, with interest payable in cash semi-annually in arrears on April 15 and October 15.

The EFH Corp. 9.75% Notes are fully and unconditionally guaranteed on a joint and several basis by EFC Holdings and Intermediate Holding. The guarantee from Intermediate Holding is secured by the pledge of all membership interests and other investments Intermediate Holding owns or holds in Oncor Holdings or any of Oncor Holdings’ subsidiaries (the Collateral). The guarantee from EFC Holdings is not secured. The EFIH Notes are secured by the Collateral on a parity lien basis with the EFH Corp. 9.75% Notes.

The EFH Corp. 9.75% Notes and EFIH Notes are senior obligations of each issuer and rank equally in right of payment with all senior indebtedness of each issuer and are senior in right of payment to any future subordinated indebtedness of each issuer. The EFH Corp. 9.75% Notes are effectively subordinated to any indebtedness of EFH Corp. secured by assets of EFH Corp. to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other liabilities of EFH Corp.’s non-guarantor subsidiaries. The EFIH Notes are effectively senior to all unsecured indebtedness of the EFIH Co-Issuers, to the extent of the value of the Collateral, and will be effectively subordinated to any indebtedness of the EFIH Co-Issuers secured by assets of the EFIH Co-Issuers other than the Collateral, to the extent of the value of the assets securing such indebtedness. Furthermore, the EFIH Notes will be structurally subordinated to all indebtedness and other liabilities of Intermediate Holding’s subsidiaries (other than EFIH Finance), including Oncor Holdings and its subsidiaries.

F-39

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

The EFH Corp. 9.75% Notes and EFIH Notes and indentures governing such notes restrict the issuers and their restricted subsidiaries’ ability to, among other things, make restricted payments, incur debt and issue preferred stock, incur liens, permit dividend and other payment restrictions on restricted subsidiaries, merge, consolidate or sell assets and engage in transactions with affiliates. These covenants are subject to a number of limitations and exceptions. The notes and indentures also contain customary events of default, including, among others, failure to pay principal or interest on the notes when due. If certain events of default occur and are continuing under a series of notes and the related indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes of such series may declare the principal amount of the notes of such series to be due and payable immediately.

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

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

Debt-Related Activity in 2008 — Repayments of long-term debt in 2008 totaling $1.167 billion represented principal payments at scheduled maturity dates as well as the remarketing of $242 million principal amount of pollution control revenue bonds discussed below, repayment of $413 million of borrowings under the TCEH Commodity Collateral Posting Facility, which fully repaid borrowings under the facility, and other repayments totaling $48 million, principally related to leases. Payments at scheduled maturity dates included $200 million of EFH Corp. senior notes, $165 million repaid under the TCEH Initial Term Loan Facility, and $99 million of Oncor transition bond principal payments.

Increases in long-term debt during 2008 totaling $3.185 billion consisted of issuances of senior secured notes issued by Oncor with an aggregate principal amount of $1.500 billion (see discussion below under “Oncor Senior Secured Notes”), borrowings under the TCEH Delayed Draw Term Loan Facility of $1.412 billion to fund expenditures related to the development of new generation facilities and the environmental retrofit program for existing lignite/coal-fueled generation facilities, the remarketing of $242 million principal amount of pollution control revenue bonds discussed immediately below and $31 million of additional borrowings under the TCEH Commodity Collateral Posting Facility.

In June 2008, TCEH remarketed the Brazos River Authority Pollution Control Revenue Bonds Series 2001A due in October 2030 and Series 2001D-1 due in May 2033 with aggregate principal amounts of $71 million and $171 million, respectively. The bonds were previously in a floating rate mode that reset weekly and were backed by two letters of credit in an aggregate amount of $247 million. As a result of the remarketing, the bonds were fixed to maturity at an interest rate of 8.25%, and the two letters of credit were cancelled. The bonds are redeemable at par beginning July 1, 2018 and are redeemable with a make-whole premium prior to July 1, 2018. These bonds were remarketed with a covenant package similar to the notes discussed below under “TCEH Senior Notes.”

Maturities — Long-term debt maturities as of December 31, 2009 are as follows (includes Oncor’s transition bond semi-annual payments):

F-40

Year
2010	$	340
2011		764
2012		1,056
2013		1,071
2014		21,746
Thereafter (a)		17,492
Unamortized fair value premium		17
Unamortized fair value discount (b)		(767	)
Unamortized discount		(15	)
Capital lease obligations		153
Total	$	41,857

(a) Long-term debt maturities for EFH Corp. (parent entity) total $7.328 billion, including $18 million held by Intermediate Holding that is not included above.

(b) Unamortized fair value discount for EFH Corp. (parent entity) totals $(599) million.

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 $22.357 billion at December 31, 2009, bear interest at per annum rates equal to, at TCEH’s option, (i) adjusted LIBOR plus 3.50% or (ii) a base rate (the higher of (1) the prime rate as announced from time to time by the administrative agent of the facilities and (2) the federal funds effective rate plus 0.50%) plus 2.50%. There is a margin adjustment mechanism in relation to term loans, revolving loans and letter of credit fees under which the applicable margins may be reduced based on the achievement of certain leverage ratio levels; there was no such reduction based upon December 31, 2009 levels. The applicable rate on borrowings under the facilities as of December 31, 2009 is provided in the long-term debt table and in the discussion of short-term borrowings above and reflects LIBOR-based borrowings.

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

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

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

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

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

• agree with individual lenders to extend the maturity of their term loans or extend or refinance their revolving credit commitments under the TCEH Senior Secured Facilities, and pay increased interest rates or otherwise modify the terms of their loans or revolving commitments in connection with such an extension, and

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

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.

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The TCEH Senior Secured Facilities are unconditionally guaranteed jointly and severally on a senior secured basis by EFC Holdings, and subject to certain exceptions, each existing and future direct or indirect wholly-owned US restricted subsidiary of TCEH. The TCEH Senior Secured Facilities, including the guarantees thereof, certain commodity hedging transactions and the interest rate swaps described under “TCEH Interest Rate Swap Transactions” 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 and (b) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.

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 (approximately $41 million quarterly), with the balance payable in October 2014. The TCEH Delayed Draw Term Loan Facility is required to be repaid in equal quarterly installments beginning in December 2009 in an aggregate annual amount equal to 1% of the actual principal outstanding under such facility as of such date, with the balance payable in October 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time until October 2013. The TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility will mature in October 2014 and December 2012, respectively.

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 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 Notes — The indebtedness under TCEH’s and TCEH Finance’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015 (Series B) (collectively, TCEH 10.25% Notes) bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.25% per annum payable in cash. The indebtedness under the TCEH Toggle Notes bear interest semiannually 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. For any interest periods until November 2012, the issuers may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new TCEH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. TCEH made the PIK election for both interest payments in 2009, increasing the principal amount. Once TCEH makes a PIK election, the election is valid for each succeeding interest payment period until TCEH revokes the election.

The TCEH 10.25% and Toggle Notes (collectively, the TCEH Senior Notes) are fully and unconditionally guaranteed on a joint and several basis 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.

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Before November 1, 2010, the issuers may redeem with the cash proceeds of certain equity offerings up to 35% of the aggregate principal amount of the TCEH 10.25% and Toggle Notes from time to time at a redemption price of 110.250% and 110.500%, respectively, of their respective aggregate principal amount plus accrued and unpaid interest, if any. The issuers may also redeem the TCEH Senior Notes at any time prior to November 1, 2011 and 2012, respectively, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. The issuers may redeem the TCEH Senior Notes, in whole or in part, at any time on or after November 1, 2011 and 2012, respectively, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFC Holdings or TCEH, the issuers may be required to offer to repurchase the TCEH Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

The indenture for the TCEH Senior Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, 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.

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

EFH Corp. Senior Notes — Borrowings under EFH Corp.’s 10.875% Notes bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.875% per annum payable in cash. Borrowings under EFH Corp.’s 11.250%/12.000% Senior Toggle Notes due November 1, 2017 bear interest semiannually 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. For any interest period 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. EFH Corp. made the PIK election for both interest payments in 2009, increasing the principal amount of the EFH Corp. Toggle Notes. Once EFH Corp. makes a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. revokes the election.

The EFH Corp. Senior Notes are fully and unconditionally guaranteed on a joint and several basis by EFC Holdings and Intermediate Holding.

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 its 10.875% and Toggle Notes from time to time at a redemption price of 110.875% and 111.250%, respectively, of their respective aggregate principal amounts, plus accrued and unpaid interest, if any. EFH Corp. may redeem the 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. EFH Corp. may also redeem the notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFH Corp., EFH Corp. must offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

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

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

Intercreditor Agreement — In October 2007, TCEH entered into an intercreditor agreement with Citibank, N.A. and five secured commodity hedge counterparties (the Secured Commodity Hedge Counterparties). In connection with the August 2009 amendment to the TCEH Secured Facilities described above, the intercreditor agreement was amended and restated (as amended and restated, the “Intercreditor Agreement”) to take into account, among other things, the possibility that TCEH could issue notes and/or loans secured by collateral (other than the collateral that secures the TCEH Senior Secured Facilities) that ranks on parity with, or junior to, TCEH’s existing first lien obligations under the TCEH Senior Secured Facilities. The Intercreditor Agreement provides that the lien granted to the Secured Commodity Hedge Counterparties will rank pari passu with the lien granted with respect to the collateral of the secured parties under the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will be entitled to share, on a pro rata basis, in the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateral in an amount provided in the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will have voting rights with respect to any amendment or waiver of any provision of the Intercreditor Agreement that changes the priority of the Secured Commodity Hedge Counterparties’ lien on such collateral relative to the priority of lien granted to the secured parties under the TCEH Senior Secured Facilities or the priority of payments to the Secured Commodity Hedge Counterparties upon a foreclosure and liquidation of such collateral relative to the priority of the lien granted to the secured parties under the TCEH Senior Secured Facilities.

TCEH Interest Rate Swap Transactions — As of December 31, 2009, TCEH has entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $16.30 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 2010 to 2014. Swaps on $1.25 billion principal amount of senior secured debt expired in 2009. Interest rate swaps on an aggregate of $15.05 billion were being accounted for as cash flow hedges related to variable interest rate cash flows until August 29, 2008, at which time these swaps were dedesignated as cash flow hedges as a result of the intent to change the variable interest rate terms of the hedged debt (from three-month LIBOR to one-month LIBOR) in connection with the planned execution of interest rate basis swaps (discussed immediately below) to further reduce the fixed borrowing costs. Based on the fair value of the positions, the cumulative unrealized mark-to-market net losses related to these interest rate swaps totaled $431 million (pre-tax) at the dedesignation date and was recorded in accumulated other comprehensive income. This balance will be reclassified into net income as interest on the hedged debt is reflected in net income. No ineffectiveness gains or losses were recorded.

As of December 31, 2009, TCEH has entered into interest rate basis swap transactions pursuant to which payments at floating interest rates of three-month LIBOR on an aggregate of $16.25 billion principal amount of senior secured term loans of TCEH were exchanged for floating interest rates of one-month LIBOR plus spreads ranging from 0.0625% to 0.353%. These transactions include swaps entered into in the year ended December 31, 2009 related to an aggregate $9.55 billion principal amount of senior secured term loans of TCEH and reflect the expiration of swaps in the year ended December 31, 2009 that related to an aggregate $6.345 billion principal amount of senior secured term loans of TCEH.

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The interest rate swap counterparties are proportionately secured by the same collateral package granted to the lenders under the TCEH Senior Secured Facilities. Subsequent to the dedesignation in August 2008 discussed above, changes in the fair value of such swaps are being reported in the income statement in interest expense and related charges, and such unrealized mark-to-market value changes totaled $696 million in net gains in the year ended December 31, 2009 and $1.477 billion in net losses in the year ended December 31, 2008. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.212 billion at December 31, 2009, of which $194 million (pre-tax) was reported in accumulated other comprehensive income.

See Note 18 for discussion of collateral investments related to certain of these interest rate swaps.

Oncor Secured Revolving Credit Facility — Oncor has a $2.0 billion credit facility to be used for its working capital and general corporate purposes, including issuances of commercial paper and letters of credit (Oncor Revolving Credit Facility). Oncor may request increases in the commitments under the facility in any amount up to $500 million, subject to the satisfaction of certain conditions. Amounts borrowed under the facility, once repaid, can be reborrowed by Oncor from time to time until October 10, 2013. Under the terms of this 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. 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 $616 million and $337 million at December 31, 2009 and 2008, respectively. The applicable rate on borrowings under this credit facility as of December 31, 2009 was 0.58% (see detail provided in the credit facilities table above).

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 — In September 2008, Oncor issued and sold senior secured notes with an aggregate principal amount of $1.500 billion consisting of $650 million aggregate principal amount of 5.95% senior secured notes maturing in September 2013, $550 million aggregate principal amount of 6.80% senior secured notes maturing in September 2018 and $300 million aggregate principal amount of 7.50% senior secured notes maturing in September 2038. Oncor used the net proceeds of approximately $1.487 billion from the sale of the Oncor notes to repay most of its borrowings under its credit facility as well as for general corporate purposes. The Oncor notes are 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. Oncor may redeem the notes, in whole or in part, at any time, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. The notes also contain customary events of default, including failure to pay principal or interest on the notes when due.

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13. COMMITMENTS AND CONTINGENCIES

Contractual Commitments

At December 31, 2009, we had noncancellable commitments under energy-related contracts, leases and other agreements as follows:

	Coal purchase agreements and coal transportation agreements		Pipeline transportation and storage reservation fees		Capacity payments under power purchase agreements (a)		Nuclear Fuel Contracts		Water Rights Contracts
2010	$	425	$	38	$	38	$	158	$	10
2011		404		36		—		127		9
2012		292		23		—		182		9
2013		259		—		—		119		8
2014		253		—		—		102		8
Thereafter		—		—		—		480		37
Total	$	1,633	$	97	$	38	$	1,168	$	81

(a) On the basis of current expectations of demand from electricity customers as compared with capacity and take-or-pay payments, management does not consider it likely that any material payments will become due for electricity not taken beyond capacity payments.

At December 31, 2009, future minimum lease payments under both capital leases and operating leases are as follows:

	Capital Leases		Operating Leases (a)
2010	$	81	$	65
2011		17		59
2012		17		56
2013		12		49
2014		7		46
Thereafter		43		286
Total future minimum lease payments		177	$	561
Less amounts representing interest		24
Present value of future minimum lease payments		153
Less current portion		76
Long-term capital lease obligation	$	77

(a) Includes operating leases with initial or remaining noncancellable lease terms in excess of one year.

In February 2010, a capital lease related to a mining railroad spur was terminated, and we purchased the related spur for $63 million. At December 31, 2009, the balance of the capital lease liability was $63 million. The assets were recorded at cost as property, plant and equipment and will be depreciated over their remaining useful lives, the weighted average of which is 23 years.

Rent reported as operating costs, fuel costs and SG&A expenses totaled $92 million for both years ended December 31, 2009 and 2008, $26 million for the period October 11, 2007 through December 31, 2007 and $66 million for the Predecessor period January 1, 2007 through October 10, 2007.

Commitment to Fund Demand Side Management Initiatives

In connection with the Merger, Texas Holdings committed to spend $100 million over the five-year period ending December 31, 2012 on demand side management or other energy efficiency initiatives. This commitment is expected to be funded by EFH Corp. and/or its subsidiaries other than Oncor. This commitment is in addition to over $300 million to be invested by Oncor for similar initiatives. See Note 6 for other provisions of the stipulation, including a similar commitment made by Oncor.

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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 6.

Guarantees

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

Disposed TXU Gas operations — In connection with the sale of TXU Gas in October 2004, EFH Corp. agreed to indemnify Atmos Energy Corporation (Atmos), until October 1, 2014, for up to $500 million for any liability related to assets retained by TXU Gas, including certain inactive gas plant sites not acquired by Atmos, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximum aggregate amount under these indemnities that we may be required to pay is $1.9 billion. To date, we have not been required to make any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.

Residual value guarantees in operating leases — We are the lessee under various operating leases that guarantee the residual values of the leased assets. At December 31, 2009, the aggregate maximum amount of residual values guaranteed was approximately $45 million with an estimated residual recovery of approximately $49 million. These leased assets consist primarily of mining equipment, rail cars and vehicles. The average life of the residual value guarantees under the lease portfolio is approximately four years.

See Note 12 for discussion of guarantees and security for certain of our indebtedness.

Letters of Credit

At December 31, 2009, TCEH had outstanding letters of credit under its credit facilities totaling $736 million as follows:

• $379 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions;

• $208 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $204 million (the letters of credit are available to fund the payment of such debt obligations and expire in 2014);

• $65 million for collateral funding transactions with counterparties to interest rate swap agreements related to TCEH debt (see Note 18), and

• $84 million for miscellaneous credit support requirements.

Litigation Related to Generation Facilities

In September 2007, 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 was filed in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. One of the plaintiffs asked the District Court to consolidate all these proceedings, and the Attorney General of Texas, on behalf of TCEQ, filed pleas to the jurisdiction seeking dismissal of all but the administrative appeal. In May 2009, the District Court dismissed the claims that contest the merits of the TCEQ’s permitting decision, but declined to dismiss the claims that contest the process by which the TCEQ handled the permit application. Oak Grove Management Company LLC (a subsidiary of TCEH) has subsequently intervened in these proceedings and has filed its own pleas to the jurisdiction asking the court to dismiss the remaining collateral attack claims. In October 2009, one of the plaintiffs ended its legal challenge to the permit. In December 2009, the Attorney General and Oak Grove Management Company LLC filed pleadings asking the court to dismiss the administrative appeal challenging the permit for want of prosecution by the plaintiffs. In January 2010, the court denied that request and set the case for a hearing on the merits on June 16, 2010. We believe the Oak Grove air permit granted by the TCEQ was issued in accordance with applicable law. There can be no assurance that the outcome of these matters will not adversely impact the Oak Grove project.

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In June and September 2008, administrative appeals were filed in the State District Court of Travis County, Texas to challenge the administrative action of the TCEQ Executive Director in issuing an air permit alteration for the previously-permitted construction and operation of the Sandow 5 generation facility in Milam County, Texas, and the failure of the TCEQ to overturn that administrative action. Plaintiffs asked that the District Court reverse the issuance of the permit alteration. The Attorney General of Texas, on behalf of TCEQ, is defending the issuance of the permit alteration. Sandow Power (a subsidiary of TCEH) intervened in support of the TCEQ. The District Court issued its ruling in November 2009 upholding the TCEQ’s issuance of the permit alteration. The plaintiffs did not appeal the court’s order by the deadline for such appeal. Thus, the matter has concluded favorably for EFH Corp.

In February 2010, the Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Big Brown generation facility. This notice is similar to the notice that Luminant received in July 2008 with respect to its Martin Lake generation facility. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.

In July 2008, Alcoa Inc. filed a lawsuit in the State District Court of Milam County, Texas against Luminant Generation and Luminant Mining (wholly-owned subsidiaries of TCEH), later adding EFH Corp., a number of its subsidiaries, Texas Holdings and Texas Energy Future Capital Holdings LLC as parties to the suit. The lawsuit makes various claims concerning the operation of the Sandow Unit 4 generation facility and the Three Oaks lignite mine, including claims for breach of contract, breach of fiduciary duty, fraud, tortious interference, civil conspiracy and conversion. The plaintiff requests money damages of no less than $500 million, declaratory judgment, rescission and other forms of equitable relief. An agreed scheduling order is currently in place setting trial for May 2010. While we are unable to estimate any possible loss or predict the outcome of this litigation, we believe the plaintiff’s claims made in this litigation are without merit and, accordingly, intend to vigorously defend this litigation.

Regulatory Investigations and Reviews

In June 2008, the EPA issued a request for information to TCEH 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. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.

Other Proceedings

In addition to the above, we 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 our financial position, results of operations or cash flows.

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 October 2009, new one-year labor agreements were reached covering bargaining unit personnel engaged in the lignite-fueled generation operations, the lignite mining operations and natural gas-fueled generation operations. In August 2008, a new labor agreement effective until August 2010 was reached covering bargaining unit personnel engaged in nuclear generation. In February 2008, a new three-year contract was ratified covering bargaining unit personnel engaged in Oncor’s operations. In June 2009, a group of approximately 50 Oncor employees voted to decertify the labor union as their representative. In December 2009, a group of approximately 350 Oncor employees elected to be represented by a labor union. We expect that any changes in collective bargaining agreements will not have a material effect on our financial position, results of operations or cash flows; however, we are unable to predict the ultimate outcome of these labor negotiations.

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Environmental Contingencies

The federal Clean Air Act, as amended (Clean Air Act) includes provisions which, among other things, place limits on SO2 and NOx emissions produced by electricity generation plants. The capital requirements of the company 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.

We must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. We believe that we are in compliance with current environmental laws and regulations; however, the impact, if any, of changes to existing regulations or the implementation of new regulations is not determinable.

The costs to comply with environmental regulations can be significantly affected by the following external events or conditions:

• enactment of state or federal regulations regarding CO2 and other greenhouse gas emissions;

• other changes to existing state or federal regulation regarding air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters, including revisions to CAIR currently being developed by the EPA as a result of court rulings discussed in Note 3, and

• the identification of sites requiring clean-up or the filing of other complaints in which we may be asserted to be potential responsible parties.

Nuclear Insurance

Nuclear insurance includes liability coverage, property damage, decontamination and premature decommissioning coverage and accidental outage and/or extra expense coverage. The liability coverage is governed by the Price-Anderson Act (Act), while the property damage, decontamination and premature decommissioning coverage are promulgated by the rules and regulations of the NRC. We intend to maintain insurance against nuclear risks as long as such insurance is available. The company is self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Such losses could have a material adverse effect on our financial condition and results of operations and cash flows.

With regard to liability coverage, the Act provides financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $12.5 billion and requires nuclear generation plant operators to provide financial protection for this amount. The US Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $12.5 billion limit for a single incident mandated by the Act. As required, the company provides this financial protection for a nuclear incident at Comanche Peak resulting in public bodily injury and property damage through a combination of private insurance and industry-wide retrospective payment plans. As the first layer of financial protection, the company has $375 million of liability insurance from American Nuclear Insurers (ANI), which provides such insurance on behalf of a major stock insurance company pool, Nuclear Energy Liability Insurance Association. The second layer of financial protection is provided under an industry-wide retrospective payment program called Secondary Financial Protection (SFP).

Under the SFP, in the event of an incident at any nuclear generation plant in the US, each operating licensed reactor in the US is subject to an assessment of up to $117.5 million plus a 3% insurance premium tax, subject to increases for inflation every five years. Assessments are limited to $17.5 million per operating licensed reactor per year per incident. The company’s maximum potential assessment under the industry retrospective plan would be $235 million (excluding taxes) per incident but no more than $35 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $375 million per accident at any nuclear facility. The SFP and liability coverage are not subject to any deductibles.

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With respect to nuclear decontamination and property damage insurance, the NRC requires that nuclear generation plant license-holders maintain at least $1.06 billion of such insurance and require the proceeds thereof to be used to place a plant in a safe and stable condition, to decontaminate it pursuant to a plan submitted to and approved by the NRC before the proceeds can be used for plant repair or restoration or to provide for premature decommissioning. The company maintains nuclear decontamination and property damage insurance for Comanche Peak in the amount of $2.25 billion (subject to $5 million deductible per accident), above which the company is self-insured. This insurance coverage consists of a primary layer of coverage of $500 million provided by Nuclear Electric Insurance Limited (NEIL), a nuclear electric utility industry mutual insurance company and $1.75 billion of premature decommissioning coverage also provided by NEIL.

The company maintains Accidental Outage Insurance through NEIL to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at Comanche Peak are out of service for more than twelve weeks as a result of covered direct physical damage. The coverage provides for weekly payments of $3.5 million for the first fifty-two weeks and $2.8 million for the next 110 weeks for each outage, respectively, after the initial twelve-week waiting period. The total maximum coverage is $490 million per unit. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident.

If NEIL’s losses exceeded its reserves for the applicable coverage, potential assessments in the form of a retrospective premium call could be made up to ten times annual premiums. The company maintains insurance coverage against these potential retrospective premium calls.

Also, under the NEIL policies, if there were multiple terrorism losses occurring within a one-year time frame, NEIL would make available one industry aggregate limit of $3.2 billion plus any amounts it recovers from other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply.

14. SHAREHOLDERS’ EQUITY

Successor

Equity Contributions, Issuances and Repurchases — In connection with the Merger, Texas Holdings made an aggregate cash equity contribution of approximately $8.3 billion to EFH Corp. in exchange for EFH Corp. issuing approximately 1.658 billion shares of its common stock to Texas Holdings. In the year ended December 31, 2008 and the period from October 11, 2007 to December 31, 2007, EFH Corp. issued an aggregate of approximately 5.5 million and 2.0 million shares of its common stock, respectively, to, or for the benefit of, certain of its officers, directors and employees for an aggregate consideration of $27.4 million and $9.8 million, respectively. The 2008 amounts include shares previously subscribed. In addition, in the years ended December 31, 2009 and 2008, EFH Corp. issued an aggregate of 1.5 million and 1.7 million shares, respectively, of its common stock to, or for the benefit of, certain officers, directors and employees as stock-based compensation as discussed in Note 22. In 2008, EFH Corp. repurchased 0.8 million shares of its common stock from employees primarily upon termination of employment or amendment of agreements, for an aggregate consideration of $3.9 million.

Effect of Sale of Noncontrolling Interests — The total amount of proceeds from the sale of noncontrolling interests in Oncor discussed in Note 15 was less than the carrying value of the interests sold by $265 million, which reflects the fact that Oncor’s carrying value after purchase accounting is based on the Merger value, while the noncontrolling interests sale value does not include a control premium. This difference was accounted for as a reduction of shareholders’ equity.

During the preparation of our December 31, 2009 financial statements, we determined that deferred income taxes related to EFH Corp.’s interest in Oncor should have been recorded upon the sale of noncontrolling interests in November 2008. Accordingly, the December 31, 2008 balance of noncurrent accumulated deferred income tax liabilities has been increased by $141 million (from the $5.926 billion previously reported) and shareholders’ equity at that date has been decreased by the same amount (from the $3.532 billion deficit previously reported). The recognition of the deferred tax liability is the result of applying rules for income tax accounting related to outside basis differences. This error did not affect net income or cash flows previously reported.

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Dividend Restrictions — The indentures governing the EFH Corp. Senior Notes, 9.75% Notes, and 10% Notes include covenants that, among other things and subject to certain exceptions, restrict our ability to pay dividends or make other distributions in respect of our capital stock. Accordingly, essentially all of our net income is restricted from being used to make distributions on our common stock unless such distributions are expressly permitted under these indentures and/or after such distributions, on a pro forma basis, after giving effect to such payment, EFH Corp.’s consolidated leverage ratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, “consolidated leverage ratio” is defined as the ratio of consolidated total indebtedness (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiaries other than Oncor Holdings and its subsidiaries. In addition, the indenture governing the EFIH Notes generally restricts Intermediate Holding from making any distribution to EFH Corp. for the ultimate purpose of making a distribution to Texas Holdings unless at the time, and after giving effect to such distribution, Intermediate Holding’s consolidated leverage ratio is equal to or less than 6.0 to 1.0. Under the indenture governing the EFIH Notes, the term “consolidated leverage ratio” is defined as the ratio of consolidated total indebtedness (as defined in the indenture) to Adjusted EBITDA on a consolidated basis.

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, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. In addition, the TCEH Senior Secured Facilities and indenture governing the TCEH Senior Notes generally restrict TCEH’s ability to make distributions or loans to any of its parent companies, EFC Holdings and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and indenture governing the TCEH Senior Notes. Those agreements generally permit TCEH to make unlimited distributions or loans to its parent companies for corporate overhead costs, SG&A expenses, taxes and principal and interest payments. In addition, those agreements contain certain investment and dividend baskets that would allow TCEH to make additional distributions and/or loans to its parent companies up to the amount of such baskets. At December 31, 2009, EFH Corp. notes payable to TCEH totaled $1.406 billion.

In addition, under applicable law, we would be prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent.

EFH Corp. has not paid any cash dividends subsequent to the Merger.

Shareholder Actions — In May 2009, the shareholders of EFH Corp. approved the change of the stated capital of EFH Corp.’s common stock, no par value per share, to an amount equal to $0.001 for each outstanding share of common stock, resulting in total stated value of outstanding common stock of $2 million. Also in May 2009, EFH Corp.’s board of directors approved a decrease in additional paid-in capital of the same amount and the allocation of $0.001 per share to stated value of common stock upon issuance of any authorized but unissued shares of common stock that may occur from time to time, with the remainder of any amounts received for such shares allocated to additional paid-in capital.

Common Stock Registration Rights — The Sponsor Group and certain other investors entered into a registration rights agreement with EFH Corp. upon closing of the Merger. Pursuant to this agreement, in certain instances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.’s common stock owned directly or indirectly by them under the Securities Act. In certain instances, the Sponsor Group and certain other investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.’s common stock under the Securities Act that it may undertake.

See Note 22 for discussion of stock-based compensation plans.

Predecessor

Declaration of Dividend — At its August 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 per share, which was paid October 1, 2007 to shareholders of record on September 7, 2007. At its May 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 per share, which was paid on July 2, 2007 to shareholders of record on June 1, 2007. At its February 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 a share, payable April 2, 2007 to shareholders of record on March 2, 2007.

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Thrift Plan — The Thrift Plan is an employee savings plan under which we matched a portion of employees’ contributions of their earnings with a contribution in shares of EFH Corp. 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 us, 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.

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.

The table below reflects the changes in the number of Predecessor common stock shares outstanding:

	Period from January 1, 2007 through October 10, 2007
Balance at beginning of period		459,244,523
Issuances under stock-based incentive compensation plans (Note 22)		2,771,257
Issued on conversion of convertible senior notes		36,372
Forfeitures and cancellations under stock-based incentive compensation plans		(900,143	)
Purchased in connection with Merger		(461,152,009	)
Balance at end of period		—

15. NONCONTROLLING INTERESTS

In November 2008, equity interests in Oncor were sold to Texas Transmission for $1.254 billion in cash. Equity interests were also indirectly sold to certain members of Oncor’s board of directors and its management team. Accordingly, after giving effect to all equity issuances, as of December 31, 2009, Oncor’s ownership was as follows: 80.03% held indirectly by EFH Corp., 0.22% held indirectly by Oncor’s management and board of directors and 19.75% held by Texas Transmission.

The proceeds (net of closing costs) of $1.253 billion received by Oncor from Texas Transmission and the members of Oncor management upon completion of these transactions were distributed ultimately to EFH Corp. Under the terms of certain financing arrangements of EFH Corp. and TCEH, upon such distribution, under certain circumstances, EFH Corp. (parent entity) is required to repay certain outstanding intercompany loans from TCEH. In November 2008, EFH Corp. repaid the $253 million balance of notes payable to TCEH that related to payments of principal and interest on EFH Corp. (parent entity) debt.

See Note 14 for discussion of amounts recorded as a reduction of shareholders’ equity as a result of the sale of Oncor interests.

Of the noncontrolling interests balance reported in the December 31, 2009 and 2008 consolidated balance sheets, $1.363 billion and $1.355 billion, respectively, related to Oncor’s noncontrolling interests. The noncontrolling interests balance reported in the December 31, 2009 consolidated balance sheet represented the proportional share of Oncor’s net assets at the date of the transaction less $96 million representing the noncontrolling interests’ share of Oncor’s net losses for the periods subsequent to the transaction (including the goodwill impairment charge), net of $58 million in cash distributions.

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In connection with the filing of a combined operating license application with the NRC for two new nuclear generation units, in January 2009, TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, known as Comanche Peak Nuclear Power Company LLC, to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. Under the terms of the joint venture agreement, a subsidiary of TCEH owns an 88% interest in the venture and a subsidiary of MHI owns a 12% interest. This joint venture is a variable interest entity, and a subsidiary of TCEH is considered the primary beneficiary.

16. FAIR VALUE MEASUREMENTS

Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a “mid-market” valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.

We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:

• Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities include exchange traded commodity contracts. For example, a significant number of our derivatives are NYMEX futures and swaps transacted through clearing brokers for which prices are actively quoted.

• Level 2 valuations use inputs, in the absence of actively quoted market prices, that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means and other valuation inputs. For example, our Level 2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes are available.

• Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assets and liabilities include certain derivatives whose values are derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means.

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.

In utilizing broker quotes, we attempt to obtain multiple quotes from brokers that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker’s publication policy, recent trading volume trends and various other factors. In addition, for valuation of interest rate swaps, we use a combination of dealer provided market valuations (generally non-binding) and Bloomberg valuations based on month-end interest rate curves and standard rate swap valuation models.

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Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including commodity prices, volatility factors, discount rates and other inputs. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Those valuation models are generally used in developing long-term forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.

With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.

At December 31, 2009, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	918	$	2,588	$	350	$	4	$	3,860
Interest rate swaps		—		64		—		—		64
Nuclear decommissioning trust — equity securities (c)		154		105		—		—		259
Nuclear decommissioning trust — debt securities (c)		—		216		—		—		216
Total assets	$	1,072	$	2,973	$	350	$	4	$	4,399
Liabilities:
Commodity contracts	$	1,077	$	796	$	269	$	4	$	2,146
Interest rate swaps		—		1,306		—		—		1,306
Total liabilities	$	1,077	$	2,102	$	269	$	4	$	3,452

(a) Level 3 assets and liabilities consist primarily of complex long-term power purchase and sales agreements, including long-term wind generation purchase contracts and certain natural gas positions (collars) in the long-term hedging program.

(b) Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities.

(c) The nuclear decommissioning trust investment is included in the Investments line on the balance sheet. See Note 19.

See Note 21 for fair value measurements related to pension and OPEB plan assets.

At December 31, 2008, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3 (a)		Total
Assets:
Commodity contracts	$	1,010	$	2,061	$	283	$	3,354
Interest rate swaps		—		142		—		142
Nuclear decommissioning trust — equity securities (b)		109		83		—		192
Nuclear decommissioning trust — debt securities (b)		—		193		—		193
Total assets	$	1,119	$	2,479	$	283	$	3,881
Liabilities:
Commodity contracts	$	1,288	$	1,274	$	355	$	2,917
Interest rate swaps		—		2,086		—		2,086
Total liabilities	$	1,288	$	3,360	$	355	$	5,003

(a) Level 3 assets and liabilities consist primarily of complex long-term power purchase and sales agreements, including long-term wind generation purchase contracts and certain natural gas positions (collars) in the long-term hedging program.

(b) The nuclear decommissioning trust investment is included in the Investments line on the balance sheet. See Note 19.

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Commodity contracts consist primarily of natural gas, electricity, fuel oil and coal derivative instruments entered into for hedging purposes and include physical contracts that have not been designated “normal” purchases or sales. See Note 18 for further discussion regarding the company’s use of derivative instruments.

Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 12 for discussion of interest rate swaps.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

The following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts) for the years ended December 31, 2009 and 2008:

	Year Ended December 31, 2009			Year Ended December 31, 2008
Balance at beginning of period	$	(72	)	$	(173	)
Total realized and unrealized gains (losses) (a):
Included in net income (loss)		115			(5	)
Included in other comprehensive income (loss)		(30	)		—
Purchases, sales, issuances and settlements (net) (b)		51			(13	)
Net transfers in and/or out of Level 3 (c)		17			119
Balance at end of period	$	81		$	(72	)
Net change in unrealized gains (losses) included in net income relating to instruments held at end of period (d)	$	105		$	87

(a) Substantially all changes in values of commodity contracts are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

(b) Settlements represent reversals of unrealized mark-to-market valuations of these positions previously recognized in net income. Purchases and issuances reflect option premiums paid or received.

(c) Includes transfers due to changes in the observability of significant inputs used in valuing derivatives. Transfers in are assumed to transfer in at the beginning of the quarter and transfers out at the end of the quarter, which is when the assessments are performed. Any changes in value during the period are reported as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities.

(d) Includes unrealized gains and losses of instruments held at the end of the period.

17. FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of significant nonderivative financial instruments were as follows:

	Successor
	December 31, 2009						December 31, 2008
	Carrying Amount			Fair Value (a)			Carrying Amount			Fair Value (a)
On balance sheet assets (liabilities):
Long-term debt (including current maturities) (b):
TCEH, EFH Corp., and other	$	(36,600	)	$	(29,115	)	$	(35,860	)	$	(24,162	)
Oncor	$	(5,104	)	$	(5,644	)	$	(5,204	)	$	(4,990	)
Total	$	(41,704	)	$	(34,759	)	$	(41,064	)	$	(29,152	)
Off balance sheet assets (liabilities):
Financial guarantees	$	—		$	(6	)	$	—		$	(3	)

(a) Fair value determined in accordance with accounting standards related to the determination of fair value.

(b) Excludes capital leases.

See Notes 16 and 18 for discussion of accounting for financial instruments that are derivatives.

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18. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Risk Management Hedging Strategy

We enter into physical and financial derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a long-term hedging program and the hedging of interest costs on our long-term debt. See Note 16 for a discussion of the fair value of all derivatives.

Long-Term Hedging Program — TCEH 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, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity is highly correlated to the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas over the next five years. These transactions are intended to hedge a majority of electricity price exposure related to expected baseload generation for this period. Changes in the fair value of the instruments under the long-term hedging program are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

Interest Rate Swap Transactions — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to a fixed basis, thereby hedging future interest costs and related cash flows. Interest rate basis swaps are used to effectively reduce the hedged borrowing costs. Changes in the fair value of the swaps are recorded as unrealized gains and losses in interest expense and related charges. See Note 12 for additional information about these and other interest rate swap agreements.

Other Commodity Hedging and Trading Activity — In addition to the long-term hedging program, TCEH enters into derivatives, including electricity, natural gas, fuel oil and coal instruments, generally for shorter-term hedging purposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets.

The following table provides detail of commodity and other derivative contractual assets and liabilities, substantially all arising from mark-to-market accounting, as reported in the balance sheet at December 31, 2009:

	Derivatives not under hedge accounting										Total
	Derivative assets				Derivative liabilities
	Commodity contracts		Interest rate swaps		Commodity contracts			Interest rate swaps
Current assets	$	2,327	$	60	$	4		$	—		$	2,391
Noncurrent assets		1,529		4		—			—			1,533
Current liabilities		—		—		(1,705	)		(687	)		(2,392	)
Noncurrent liabilities		—		—		(441	)		(619	)		(1,060	)
Net assets (liabilities)	$	3,856	$	64	$	(2,142	)	$	(1,306	)	$	472

As of December 31, 2009, there were no derivative positions accounted for as cash flow or fair value hedges.

Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled $358 million and $190 million in net liabilities at December 31, 2009 and 2008, respectively, which do not include the collateral investments related to certain interest rate swaps and commodity positions discussed immediately below. Reported amounts as presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positions with the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.

In early 2009, we entered into collateral funding transactions with counterparties to certain interest rate swap agreements related to TCEH debt. Under the terms of these transactions, which we elected to enter into as a cash management measure, as of December 31, 2009, EFH Corp. (parent) has posted $400 million in cash and TCEH has posted $65 million in letters of credit to the counterparties, with the outstanding balance of such collateral earning interest. TCEH had also entered into commodity hedging transactions with one of these counterparties, and under an arrangement effective August 2009, both the interest rate swaps and certain of the commodity hedging transactions with the counterparty are under the same derivative agreement, which continues to be secured by a first-lien interest in the assets of TCEH. We are not required to post any additional collateral to these counterparties, regardless of the net mark-to-market liability under the applicable derivative agreement, and the applicable counterparty will return the cash collateral to the extent the mark-to-market liability under the applicable derivative agreement falls below the funded amount, subject to a $50 million minimum transfer amount. At December 31, 2009, the collateral posted approximated the net mark-to-market liability of the related derivatives. Under the agreements, the counterparties are to return any remaining collateral, along with accrued and unpaid interest, on March 31, 2010. The cash collateral was recorded as an investment and is presented in the balance sheet (including accrued interest) as a separate line item under current assets.

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The following table presents the pre-tax effect of derivatives not under hedge accounting on net income, including realized and unrealized effects:

Derivative (Income statement presentation)	Year Ended December 31, 2009
Commodity contracts (Net gain (loss) from commodity hedging and trading activities)	$	1,741
Interest rate swaps (Interest expense and related charges)		12
Net gain	$	1,753

Amounts reported in the income statement in net gain (loss) from commodity hedging and trading activities include net “day one” mark-to-market losses of $2 million, $68 million and $8 million in the 2009, 2008 and 2007 Successor periods, respectively, and $201 million in the 2007 Predecessor period. Substantially all of these losses arose from a related series of derivative transactions entered into under the long-term hedging program. The 2007 Predecessor period amount is net of a $30 million “day one” gain associated with a long-term power purchase agreement.

A multi-year power sales agreement was entered into with Alcoa Inc. in the 2007 Predecessor period. The agreement was determined to be a derivative and resulted in a “day one” mark-to-market loss of $235 million. The agreement was entered into concurrently with the transfer of an air permit from Alcoa Inc. to a subsidiary of ours 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 us by providing the right and ability to develop, construct and operate the new lignite-fueled generation unit at Sandow. In consideration of this right and ability, the initial “day one” loss of the sales agreement, as well as a $29 million below market 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 following tables present the pre-tax effect of derivative instruments accounted for as cash flow hedges on net income (loss) and other comprehensive income (loss) (OCI) for the year ended December 31, 2009:

Derivative	Amount of (loss) recognized in OCI (effective portion)			Income statement presentation of gain (loss) reclassified from accumulated OCI into income (effective portion)	Amount
Interest rate swaps	$	—		Interest expense and related charges	$	(184	)
Commodity contracts		(30	)	Fuel, purchased power costs and delivery fees		(2	)
Total	$	(30	)	Operating revenues		(2	)
					$	(202	)

There were no ineffectiveness net gains or losses related to transactions designated as cash flow hedges in the year ended December 31, 2009.

Accumulated other comprehensive income related to cash flow hedges at December 31, 2009 totaled $128 million in net losses (after-tax), substantially all of which relates to interest rate swaps. We expect that $59 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of December 31, 2009 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

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Derivative Volumes — The following table presents the gross notional amounts of derivative volumes at December 31, 2009:

Derivative type	Notional Volume		Unit of Measure
Interest rate swaps:
Floating/fixed	$	18,000		Million US dollars
Basis	$	16,250		Million US dollars
Natural gas:
Long-term hedge forward sales and purchases (a)		3,402		Million MMBtu
Locational basis swaps		1,010		Million MMBtu
All other		1,433		Million MMBtu
Electricity		198,230		GWh
Coal		6		Million tons
Fuel oil		161		Million gallons

(a) Represents gross notional forward sales, purchases and options of fixed and basis (price point) transactions in the long-term hedging program. The net amount of these transactions, excluding basis transactions, is 1.6 billion MMBtu.

Credit Risk-Related Contingent Features

The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of those agreements require the posting of collateral if our credit rating is downgraded by one or more of the credit rating agencies; however, due to our below investment grade ratings, substantially all of such collateral posting requirements are already effective.

As of December 31, 2009, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $687 million. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $152 million as of December 31, 2009. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of December 31, 2009, the remaining related liquidity requirement would have totaled $20 million after reduction for net accounts receivable and derivative assets under netting arrangements.

In addition, certain derivative agreements that are collateralized primarily with asset liens include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. As of December 31, 2009, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $1.482 billion (before consideration of the amount of assets under the liens). The liquidity exposure associated with these liabilities was reduced by cash collateral and letters of credit posted with counterparties totaling $489 million as of December 31, 2009. If all the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, had been triggered as of December 31, 2009, the remaining related liquidity requirement would have totaled $480 million after reduction for derivative assets under netting arrangements (before consideration of the amount of assets under the liens). See Note 12 for a description of other obligations that are supported by asset liens.

As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $2.169 billion at December 31, 2009. This amount is before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets under related liens.

Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.

Concentrations of Credit Risk

TCEH has significant concentrations of credit risk with the counterparties to its derivative contracts. As of December 31, 2009, total credit risk exposure to all counterparties related to derivative contracts totaled $4.0 billion. The net exposure to those counterparties totaled $1.3 billion after taking into effect master netting arrangements, setoff provisions and collateral. As of December 31, 2009, the credit risk exposure to the banking and financial sector represented more than 90% of the total credit risk exposure. As of December 31, 2009, the largest net exposure to a single counterparty totaled $536 million. Exposure to the banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because substantially all of this exposure is with counterparties with credit ratings of “A” or better. However, this concentration increases the risk that a default by any of these counterparties would have a material adverse effect on our financial condition and results of operations.

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The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies 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. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. 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. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.

19. INVESTMENTS

The investments balance consists of the following:

	December 31, 2009		December 31, 2008
Nuclear decommissioning trust	$	475	$	385
Assets related to employee benefit plans, including employee savings programs, net of distributions		184		210
Land		43		44
Investment in natural gas gathering pipeline business (a)		44		—
Miscellaneous other		4		6
Total investments	$	750	$	645

(a) A controlling interest in this previously consolidated subsidiary was sold in August 2009.

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:

	December 31, 2009
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	211	$	8	$	(3	)	$	216
Equity securities (c)		195		83		(19	)		259
Total	$	406	$	91	$	(22	)	$	475

	December 31, 2008
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	203	$	4	$	(14	)	$	193
Equity securities (c)		181		46		(35	)		192
Total	$	384	$	50	$	(49	)	$	385

(a) Includes realized gains and losses of securities sold.

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(b) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.44% and 3.77% and an average maturity of 7.8 years and 8.0 years at December 31, 2009 and 2008, respectively.

(c) The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.

Debt securities held at December 31, 2009 mature as follows: $82 million in one to five years, $32 million in five to ten years and $102 million after ten years.

Assets Related to Employee Benefit Plans

The majority of these assets represent cash surrender values of life insurance policies that are purchased to fund liabilities under deferred compensation plans. We pay the premiums and are the beneficiary of these life insurance policies. As of December 31, 2009 and 2008, the face amount of these policies totaled $322 million and $481 million, and the net cash surrender values totaled $124 million and $155 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.

20. TERMINATION OF OUTSOURCING ARRANGEMENTS

In connection with the closing of the Merger, EFH Corp., TCEH and Oncor commenced a review, under the change of control provision, of certain outsourcing arrangements with Capgemini, Capgemini America, Inc. and Capgemini North America, Inc. (collectively, CgE). In 2008, EFH Corp. and TCEH executed a Separation Agreement with CgE. Simultaneous with the execution of that Separation Agreement, Oncor entered into a substantially similar Separation Agreement with CgE. The Separation Agreements principally provide for (i) notice of termination of each of the Master Framework Agreements, dated as of May 17, 2004, as each has been amended, between Capgemini and each of TCEH and Oncor and the related service agreements under each of the Master Framework Agreements and (ii) termination of the joint venture arrangements between EFH Corp. (and its applicable subsidiaries) and CgE. Under the Master Framework Agreements and related services agreements, Capgemini provided outsourced support services, including information technology, customer care and billing, human resources, procurement and certain finance and accounting activities. As a result, during 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 us and third parties;

• we received approximately $70 million in exchange for the termination of a purchase option agreement pursuant to which our subsidiaries had the right to “put” to Capgemini (and Capgemini had the right to “call” from a subsidiary of ours) our 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 us in July 2004.

Under the Separation Agreements, the parties also entered into a mutual release of all claims under the Master Framework Agreements and related services agreements and the joint venture agreements, subject to certain defined exceptions, resulting in our receipt of $10 million in cash settlement.

The carrying value of the partnership interest was $2.9 million, and the carrying value of the purchase option was $177 million prior to the application of purchase accounting (recorded as a noncurrent asset). The effects of the termination of the outsourcing arrangements, including an accrued liability of $54 million for incremental costs to exit and transition the services, were included in the final purchase price allocation. See Note 2 for additional disclosure, including a reversal to income of a portion of the liability recorded in purchase accounting.

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

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

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Effective October 1, 2007, all new employees, with the exception of employees hired by Oncor, are not eligible to participate in the Retirement Plan. New hires at Oncor are eligible to participate in the Cash Balance Formula of the Retirement Plan. It is our policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations.

We also have supplemental unfunded retirement plans for certain employees whose retirement benefits cannot fully be earned under the qualified Retirement Plan, the information for which is included below.

We offer OPEB in the form of health care and life insurance to eligible employees and their eligible dependents upon the retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service.

Regulatory Recovery of Pension and OPEB Costs

PURA provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, which in addition to Oncor’s own employees consists largely of active and retired personnel engaged in TCEH’s activities, related to service of those additional personnel prior to the deregulation and disaggregation of our businesses effective January 1, 2002. Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Amounts deferred are ultimately subject to regulatory approval. As of December 31, 2009, Oncor had recorded regulatory assets totaling $889 million related to pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilities that otherwise would be recorded as other comprehensive income.

Pension and OPEB Costs Recognized as Expense

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Pension costs	$	44		$	21		$	(1	)	$	34
OPEB costs		70			58			11			49
Total benefit costs		114			79			10			83
Less amounts deferred principally as a regulatory asset or property		(66	)		(42	)		(8	)		(43	)
Net amounts recognized as expense	$	48		$	37		$	2		$	40

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

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Detailed Information Regarding Pension Benefits

The following information is based on December 31, 2009, 2008, 2007 and October 10, 2007 measurement dates:

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Assumptions Used to Determine Net Periodic Pension Cost:
Discount rate		6.90	%		6.55	%		6.45	%		5.90	%
Expected return on plan assets		8.25	%		8.25	%		8.75	%		8.75	%
Rate of compensation increase		3.75	%		3.70	%		3.44	%		3.44	%
Components of Net Pension Cost:
Service cost	$	38		$	36		$	10		$	30
Interest cost		159			148			36			107
Expected return on assets		(166	)		(165	)		(47	)		(119	)
Amortization of prior service cost		1			1			—			1
Amortization of net loss		12			1			—			15
Recognized curtailment loss		—			—			—			—
Net periodic pension cost	$	44		$	21		$	(1	)	$	34
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net loss (gain)	$	45		$	204		$	20		$	(52	)
Transition obligation (asset)		—			—			—			—
Prior service cost (credit)		—			—			—			—
Amortization of net loss (gain)		—			—			—			(3	)
Amortization of transition obligation (asset)		—			—			—			—
Amortization of prior service cost		—			—			—			(1	)
Reclassification to regulatory asset		—			(6	)
Purchase accounting adjustment		—			(10	)		—			49
Total recognized in other comprehensive income	$	45		$	188		$	20		$	(7	)
Total recognized in net periodic benefit cost and other comprehensive income	$	89		$	209		$	19		$	27
Assumptions Used to Determine Benefit Obligations:
Discount rate		5.90			6.90	%		6.55	%		6.45	%
Rate of compensation increase		3.71	%		3.75	%		3.70	%		3.44	%

	Successor
	Year Ended December 31, 2009			Year Ended December 31, 2008
Change in Pension Obligation:
Projected benefit obligation at beginning of year	$	2,337		$	2,335
Service cost		38			36
Interest cost		160			148
Plan amendments		—			—
Actuarial (gain) loss		326			(58	)
Benefits paid		(133	)		(124	)
Settlements		14			—
Projected benefit obligation at end of year	$	2,742		$	2,337
Accumulated benefit obligation at end of year	$	2,581		$	2,203
Change in Plan Assets:
Fair value of assets at beginning of year	$	1,736		$	2,108
Actual return (loss) on assets		292			(412	)
Employer contributions (a)		109			164
Benefits paid		(133	)		(124	)
Settlements		—			—

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	Successor
	Year Ended December 31, 2009			Year Ended December 31, 2008
Fair value of assets at end of year	$	2,004		$	1,736
Funded Status:
Projected pension benefit obligation	$	(2,742	)	$	(2,337	)
Fair value of assets		2,004			1,736
Funded status at end of year	$	(738	)	$	(601	)
Amounts Recognized in the Balance Sheet Consist of:
Other noncurrent assets (b)	$	10		$	10
Other current liabilities		(4	)		(4	)
Other noncurrent liabilities		(744	)		(607	)
Net liability recognized	$	(738	)	$	(601	)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net loss	$	252		$	208
Prior service cost		—			—
Net amount recognized	$	252		$	208
Amounts Recognized as Regulatory Assets Consist of:
Net loss	$	529		$	387
Prior service cost		1			1
Net amount recognized	$	530		$	388

(a) 2009 amount includes transfers of investments related to the salary deferral and supplemental retirement plans totaling $31 million.

(b) Amounts represent overfunded plans.

The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated benefit obligation (ABO) in excess of the fair value of plan assets.

	Successor
	December 31, 2009		December 31, 2008
Pension Plans with PBO and ABO in Excess Of Plan Assets:
Projected benefit obligations	$	2,738	$	2,332
Accumulated benefit obligation		2,577		2,199
Plan assets		1,989		1,721

Pension Plan Investment Strategy and Asset Allocations

Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Equity securities are held to achieve returns in excess of passive indexes by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging international markets. Fixed income securities include primarily corporate bonds from a diversified range of companies, US Treasuries and agency securities and money market instruments. Our investment strategy for fixed income investments is to maintain a high grade portfolio of securities which assist us in managing the volatility and magnitude of plan contributions and expense.

The target asset allocation ranges of pension plan investments by asset category are as follows:

Asset Category	Target Allocation Ranges
US equities	15%-50%
International equities	5%-20%
Fixed income (a)	40%-70%
Other	0%-10%

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Fair Value Measurement of Pension Plan Assets

At December 31, 2009, pension plan assets measured at fair value on a recurring basis (see Note 16) consisted of the following:

Asset Category	Level 1		Level 2		Level 3		Total
Interest-bearing cash	$	—	$	99	$	—	$	99
Equity securities:
US		340		242		—		582
International		257		79		—		336
Fixed income securities:
Corporate bonds (a)		—		908		—		908
US Treasuries		—		21		—		21
Other (b)		—		44		—		44
Preferred securities		—		—		14		14
Total assets	$	597	$	1,393	$	14	$	2,004

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s.

(b) Other consists primarily of US agency securities.

At December 31, 2008, pension plan assets measured at fair value on a recurring basis consisted of the following:

Asset Category	Level 1		Level 2		Level 3		Total
Interest-bearing cash	$	—	$	141	$	—	$	141
Equity securities:
US		272		213		—		485
International		220		80		—		300
Fixed income securities:		—		317		—		317
Corporate bonds (a)
US Treasuries		—		368		—		368
Other (b)		—		110		1		111
Preferred securities		—		—		14		14
Total assets	$	492	$	1,229	$	15	$	1,736

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s.

(b) Other consists primarily of US agency securities.

The following table presents the changes in fair value of the Level 3 pension plan assets for the years ended December 31, 2009 and 2008:

	Year Ended December 31, 2009			Year Ended December 31, 2008
Balance at beginning of period	$	15		$	14
Actual return on plan assets:
Relating to assets held		(1	)		—
Relating to assets sold during the period		—			—
Purchases, sales and settlements		—			1
Transfers in and/or out of Level 3		—			—
Balance at end of period	$	14		$	15
Net unrealized gains (losses) included in net assets held at end of period	$	—		$	—

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Detailed Information Regarding Postretirement Benefits Other Than Pensions

The following OPEB information is based on December 31, 2009, 2008, 2007 and October 10, 2007 measurement dates:

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate		6.85	%		6.55	%		6.45	%		5.90	%
Expected return on plan assets		7.64	%		7.90	%		8.67	%		8.67	%
Components of Net Postretirement Benefit Cost:
Service cost	$	10		$	10		$	3		$	9
Interest cost		61			59			14			41
Expected return on assets		(13	)		(20	)		(6	)		(15	)
Amortization of net transition obligation		1			1			—			1
Amortization of prior service cost/(credit)		(1	)		(1	)		—			(2	)
Amortization of net loss		12			9			—			15
Net periodic OPEB cost	$	70		$	58		$	11		$	49
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net loss (gain)	$	15		$	1		$	36		$	(16	)
Transition obligation (asset)		—			—			—			—
Prior service cost (credit)		—			—			—			—
Amortization of net loss (gain)		—			—			—			—
Amortization of transition obligation (asset)		—			—			—			—
Amortization of prior service cost		—			—			—			1
Reclassification to regulatory asset		—			(28	)
Purchase accounting adjustment		—			(1	)		—			13
Total recognized in other comprehensive income	$	15		$	(28	)	$	36		$	(2	)
Total recognized in net periodic benefit cost and other comprehensive income	$	85		$	30		$	47		$	47
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate		5.90	%		6.85	%		6.55	%		6.45	%

	Successor
	Year Ended December 31, 2009			Year Ended December 31, 2008
Change in Postretirement Benefit Obligation:
Benefit obligation at beginning of year	$	919		$	928
Service cost		10			10
Interest cost		61			59
Participant contributions		23			16
Medicare Part D reimbursement		6			4
Actuarial (gain)/loss		108			(35	)
Benefits paid		(64	)		(63	)
Benefit obligation at end of year	$	1,063		$	919
Change in Plan Assets:
Fair value of assets at beginning of year	$	198		$	260
Actual return (loss) on assets		32			(54	)
Employer contributions		22			35
Participant contributions		23			16
Medicare Part D reimbursement		—			4
Benefits paid		(64	)		(63	)
Fair value of assets at end of year	$	211		$	198

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	Successor
	Year Ended December 31, 2009			Year Ended December 31, 2008
Funded Status:
Benefit obligation	$	(1,063	)	$	(919	)
Fair value of assets		211			198
Funded status at end of year	$	(852	)	$	(721	)

	Successor
	Year Ended December 31, 2009			Year Ended December 31, 2008
Amounts Recognized on the Balance Sheet Consist of:
Other noncurrent liabilities	$	(852	)	$	(721	)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net loss	$	23		$	7
Prior service cost credit		—			—
Net transition obligation		—			—
Net amount recognized	$	23		$	7
Amounts Recognized as Regulatory Assets Consist of:
Net loss	$	242		$	174
Prior service cost credit		(7	)		(8	)
Net transition obligation		4			5
Net amount recognized	$	239		$	171

The following tables provide information regarding the assumed health care cost trend rates.

	Successor
	December 31, 2009			December 31, 2008
Assumed Health Care Cost Trend Rates-Not Medicare Eligible :
Health care cost trend rate assumed for next year		8.00	%		8.64	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate		2016			2017
Assumed Health Care Cost Trend Rates-Medicare Eligible :
Health care cost trend rate assumed for next year		7.00	%		8.32	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate		2016			2017

	1-Percentage Point Increase		1-Percentage Point Decrease
Sensitivity Analysis of Assumed Health Care Cost Trend Rates:
Effect on accumulated postretirement obligation	$	126	$	(105	)
Effect on postretirement benefits cost		10		(8	)

OPEB Plan Investment Strategy and Asset Allocation

Our investment objective for the OPEB plan primarily follows the objectives of the Retirement Plan discussed above, while maintaining sufficient cash and short-term investments to pay near-term benefits and expenses.

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Fair Value Measurement of OPEB Plan Assets

At December 31, 2009, OPEB plan assets measured at fair value on a recurring basis consisted of the following:

Asset Category	Level 1		Level 2		Level 3		Total
Interest-bearing cash	$	—	$	18	$	—	$	18
Equity securities:
US		56		13		—		69
International		27		4		—		31
Fixed income securities:
Corporate bonds (a)		—		50		—		50
US Treasuries		—		1		—		1
Other (b)		39		2		—		41
Preferred securities		—		—		1		1
Total assets	$	122	$	88	$	1	$	211

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s.

(b) Other consists primarily of US agency securities.

At December 31, 2008, OPEB plan assets measured at fair value on a recurring basis consisted of the following:

Asset Category	Level 1		Level 2		Level 3		Total
Interest-bearing cash	$	—	$	19	$	—	$	19
Equity securities:
US		70		13		—		83
International		13		5		—		18
Fixed income securities:
Corporate bonds (a)		—		19		—		19
US Treasuries		—		22		—		22
Other (b)		29		7		—		36
Preferred securities		—		—		1		1
Total assets	$	112	$	85	$	1	$	198

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s.

(b) Other consists primarily of US agency securities.

There was no change in the fair values of Level 3 assets in the periods presented.

Expected Long-Term Rate of Return on Assets Assumption

The Retirement Plan strategic asset allocation is determined in conjunction with the plan’s advisors and utilizes a comprehensive Asset-Liability modeling study to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.

Retirement Plan
Asset Class	Expected Long-Term Rate of Return
US equity securities		9.3	%
International equity securities		10.3	%
Fixed income securities		7.0	%
Preferred securities		8.0	%
		8.0	%

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OPEB Plan
Plan Type	Expected Long-Term Rate of Return
401(h) accounts	8.0%
Life Insurance VEBA	7.5%
Union VEBA	7.5%
Non-Union VEBA	4.0%
	7.6%

Significant Concentrations of Risk

The plans’ investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.

Assumed Discount Rate

We selected the assumed discount rate using the Hewitt Top Quartile yield curve, which is based on actual corporate bond yields and at December 31, 2009 consisted of 111 corporate bonds rated AA or higher as reported by either Moody’s or S&P.

Amortization in 2010

In 2010, we estimate amortization of the net actuarial loss and prior service cost for the defined benefit pension plan from accumulated other comprehensive income into net periodic benefit cost will be $51 million and $1 million, respectively. We estimate amortization of the net actuarial loss, prior service credit, and transition obligation for the OPEB plan from accumulated other comprehensive income into net periodic benefit cost will be $21 million, a $1 million credit and $1 million, respectively.

Contributions in 2010

Estimated funding for calendar year 2010 totals $45 million for the Retirement Plan and $24 million for the OPEB plan.

Future Benefit Payments

Estimated future benefit payments to beneficiaries are as follows:

	Successor
	2010		2011		2012		2013		2014		2015-19
Pension benefits	$	142	$	149	$	161	$	171	$	173	$	1,020
OPEB	$	54	$	57	$	60	$	63	$	67	$	377
Medicare Part D subsidies received	$	6	$	7	$	7	$	8	$	8	$	49

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Thrift Plan

Our employees may participate in a qualified savings plan, the Thrift Plan. This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. 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. Effective January 1, 2006 through October 10, 2007, employees could reallocate or transfer all or part of their accumulated or future employer matching contributions to any of the plan’s other investment options. As of October 10, 2007, employer matching contributions are made in cash and may be allocated by participants to any of the plan’s investment options. Our contributions to the Thrift Plan totaled $28 million, $25 million, $6 million and $33 million in the years ended December 31, 2009 and 2008, the period October 11, 2007 through December 31, 2007 and the period January 1, 2007 through October 10, 2007, respectively. See Note 14 for additional information related to the Thrift Plan.

22. STOCK-BASED COMPENSATION

Successor — EFH Corp. 2007 Stock Incentive Plan

In December 2007, we established the 2007 Stock Incentive Plan for Key Employees of EFH Corp. and its Affiliates (2007 SIP). Incentive awards under the 2007 SIP may be granted to directors and officers and qualified managerial employees of EFH Corp. or its subsidiaries or affiliates in the form of non-qualified stock options, stock appreciation rights, restricted shares, deferred shares, shares of common stock, the opportunity to purchase shares of common stock and other awards that are valued in whole or in part by reference to, or are otherwise based on the fair market value of EFH Corp.’s shares of common stock. The 2007 SIP permits the grant of awards for 72 million shares of common stock, subject to adjustments under applicable laws for certain events, such as a change in control, and no such grants may be issued after December 26, 2017. Shares related to grants that are forfeited, terminated, cancelled, expire unexercised, withheld to satisfy tax withholding obligations, or are repurchased by the Company are available for new grants under the 2007 SIP.

Stock Options — Under the terms of the 2007 SIP, options to purchase 14.7 million, 33.1 million and 19.5 million shares of EFH Corp. common stock were granted to certain management employees in 2009, 2008 and December 2007, respectively. Of the options granted in 2009, 9.2 million were granted in exchange for previously granted options. Vested awards must be exercised within 10 years of the grant date. The options initially provided the holder the right to purchase EFH Corp. common stock for $5.00 per share. The terms of the options were fixed at grant date. The stock option awards under the 2007 SIP consist of three types of stock options. One-half of the options initially granted vest solely based upon continued employment over a specific period of time, generally five years, with the options vesting ratably on an annual basis over the period (Time-Based Options). One-half of the options initially granted vest based upon both continued employment and the achievement of targeted five-year EFH Corp. EBITDA levels (Performance-Based Options). The Performance-Based Options may also vest in part or in full upon the occurrence of certain specified liquidity events. All options remain exercisable for ten years from the date of grant. Prior to vesting, expenses are recorded if the achievement of the EBITDA levels is probable, and amounts recorded are adjusted or reversed if the probability of achievement of such levels changes. Probability of vesting is evaluated at least each quarter.

In October 2009, in consideration of the recent economic dislocation and the desire to provide incentives for retention, grantees of Performance-Based Options (excluding named executive officers and a small group of other employees) were provided an offer, which substantially all accepted, to exchange their unvested Performance-Based Options granted under the 2007 SIP with a strike price of $5.00 per share and a vesting schedule through October 2012 for new time-based stock options (Cliff-Vesting Options) granted under the 2007 SIP with a strike price of $3.50 per share (the then most recent market valuation of each share), with one-half of these options vesting in September 2012 and one-half of these options vesting in September 2014. Additionally, 3.1 million Cliff-Vesting Options were granted to certain Named Executive Officers and a small group of other employees under the 2007 SIP with a strike price of $3.50 per share, vesting in September 2014. Substantially all of this group of employees also accepted an offer to exchange half of their unvested Performance-Based Options under the 2007 SIP with a strike price of $5.00 per share and a vesting schedule through December 2012 for new time-based stock options granted under the 2007 SIP with a strike price of $3.50 per share, vesting in September 2014.

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

	Successor
	Year Ended December 31, 2009	Year Ended December 31, 2008	Period from October 11, 2007 through December 31, 2007	Year Ended December 31, 2009	Year Ended December 31, 2008	Period from October 11, 2007 through December 31, 2007
Assumptions	Time-Based Options			Performance-Based Options
Expected volatility	30%	30% – 33%	30%	30%	30% – 33%	30%
Expected annual dividend	—	—	—	—	—	—
Expected life (in years)	6.4 - 7.4	6.0 - 6.5	6.4	5.3 - 7.6	5.0 - 7.3	5.4 – 7.4
Risk-free rate	2.54% – 3.14%	1.51% – 3.50%	3.81%	2.51% – 3.25%	1.35% – 3.64%	3.92%

The weighted average grant-date fair value of the Time-Based Options granted in 2009, 2008 and December 2007 was $1.32, $1.89 and $1.92 per option, respectively. The weighted-average grant-date fair value of the Performance-Based Options granted in 2009, 2008 and December 2007 ranged from $1.16 to $1.91, $1.73 to $2.25 and $1.74 to $2.09, respectively, depending upon the performance period.

Compensation expense for Time-Based Options is based on the grant-date fair value and recognized over the vesting period as employees perform services. During 2009, 2008 and the 2007 Successor period, $8.6 million, $11.9 million and less than $100,000, respectively, was recognized as expense for Time-Based Options.

As of December 31, 2009, there was approximately $48.9 million of unrecognized compensation expense related to nonvested Time-Based Options, which is expected to be recognized ratably over a remaining weighted-average period of approximately three to five years.

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

	Year Ended December 31, 2009
Options	Options (millions)			Weighted Average Exercise Price		Aggregate Intrinsic Value (millions)
Total outstanding at beginning of period		24.6		$	5.00	$	—
Granted		13.9			3.50		—
Exercised		—			—		—
Forfeited		(2.9	)		5.00		—
Total outstanding at end of period (weighted average remaining term of 8 - 10 years)		35.6			4.42		—
Exercisable at end of period (weighted average remaining term of 8 - 10 years)		(4.7	)		5.00		—
Expected forfeitures		(0.3	)		5.00		—
Expected to vest at end of period (weighted average remaining term of 8 - 10 years)		30.6			4.32		—

F-70

	Year Ended December 31, 2008
Options	Options (millions)			Weighted Average Exercise Price		Aggregate Intrinsic Value (millions)
Total outstanding at beginning of period		9.8		$	5.00	$	—
Granted		16.8			5.00		—
Exercised		—			—		—
Forfeited		(2.0	)		5.00		—
Total outstanding at end of period (weighted average remaining term of 9 years)		24.6			5.00		—
Exercisable at end of period (weighted average remaining term of 9 years)		(4.7	)		5.00		—
Expected forfeitures		(0.4	)		5.00		—
Expected to vest at end of period (weighted average remaining term of 9 years)		19.5			5.00		—

	Period from October 11, 2007 through December 31, 2007
Options	Options (millions)			Weighted Average Exercise Price		Aggregate Intrinsic Value (millions)
Total outstanding at beginning of period		—		$	—	$	—
Granted		9.8			5.00		—
Exercised		—			—		—
Forfeited		—			—		—
Total outstanding at end of period (weighted average remaining term of 10 years)		9.8			5.00		—
Exercisable at end of period (weighted average remaining term of 10 years)		—			—		—
Expected forfeitures		(0.5	)		5.00		—
Expected to vest at end of period (weighted average remaining term of 10 years)		9.3			5.00		—

	Year Ended December 31, 2009					Year Ended December 31, 2008					Period from October 11, 2007 through December 31, 2007
Nonvested Options	Options (millions)			Weighted Average Grant- Date Fair Value		Options (millions)			Weighted Average Grant- Date Fair Value		Options (millions)		Grant-Date Fair Value
Total nonvested at beginning of period		19.9		$	2.05		9.8		$	1.92		—	$	—
Granted		13.9			1.32		16.8			1.89		9.8		1.92
Vested		(4.7	)		1.86		(4.7	)		1.80		—		—
Forfeited		(2.9	)		1.85		(2.0	)		1.92		—		—
Total nonvested at end of period		26.2			1.67		19.9			2.05		9.8		1.92

Compensation expense for Performance-Based Options is based on the grant-date fair value and recognized over the requisite performance and service periods for each tranche of options depending upon the achievement of financial performance, or if certain liquidity events occur, as discussed above. No amounts were expensed in 2009 for Performance-Based Options because the 2009 EBITDA target was not met. Additionally, most participants’ Performance-Based Options were exchanged for Time-Based Options in 2009. Expense recognized for Performance-Based Options in 2008 totaled $8.1 million. No amounts were expensed in the 2007 Successor period for Performance-Based Options because the performance period for the first tranche of the options did not begin until January 1, 2008.

As of December 31, 2009, there was approximately $19.1 million of unrecognized compensation expense related to nonvested Performance-Based Options, which we could record as an expense over a remaining weighted-average period of approximately three to five years, subject to the achievement of financial performance being probable. A total of 4.8 million of the 2008 and none of the 2009 Performance-Based Options have vested.

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

F-71

	Year Ended December 31, 2009
Options	Options (millions)			Weighted Average Exercise Price		Aggregate Intrinsic Value (millions)
Outstanding at beginning of period		23.9		$	5.00	$	—
Granted		0.8			3.50		—
Exercised		—			—		—
Forfeited		(3.0	)		5.00		—
Exchanged		(9.2	)		5.00		—
Total outstanding at end of period (weighted average remaining term of 8 — 10 years)		12.5			4.90		—
Exercisable at end of period (weighted average remaining term of 8 — 10 years)		(4.8	)		5.00		—
Expected forfeitures		(0.3	)		5.00		—
Expected to vest at end of period (weighted average remaining term of 8 — 10 years)		7.4			4.90		—

	Year Ended December 31, 2008
Options	Options (millions)			Weighted Average Exercise Price		Aggregate Intrinsic Value (millions)
Total outstanding at beginning of period		9.8		$	5.00	$	—
Granted		16.2			5.00		—
Exercised		—			—		—
Forfeited		(2.1	)		5.00		—
Total outstanding at end of period (weighted average remaining term of 9 years)		23.9			5.00		—
Exercisable at end of period (weighted average remaining term of 9 years)		—			—		—
Expected forfeitures		(0.5	)		5.00		—
Expected to vest at end of period (weighted average remaining term of 9 years)		23.4			5.00		—

	Period from October 11, 2007 through December 31, 2007
Options	Options (millions)			Weighted Average Exercise Price		Aggregate Intrinsic Value (millions)
Total outstanding at beginning of period		—		$	—	$	—
Granted		9.8			5.00		—
Exercised		—			—		—
Forfeited		—			—		—
Total outstanding at end of period (weighted average remaining term of 10 years)		9.8			5.00		—
Exercisable at end of period (weighted average remaining term of 10 years)		—			—		—
Expected forfeitures		(0.5	)		5.00		—
Expected to vest at end of period (weighted average remaining term of 10 years)		9.3			5.00		—

	Year Ended December 31, 2009					Year Ended December 31, 2008					Period from October 11, 2007 through December 31,  2007
Nonvested Options	Options (millions)			Grant-Date Fair Value		Options (millions)			Grant-Date Fair Value		Options (millions)		Grant-Date Fair Value
Total nonvested at beginning of period		23.9		$	1.73 – 2.21		9.8		$	1.74 – 2.09		—	$	—
Granted		0.8			1.16 – 1.91		16.2			1.73 – 2.25		9.8		1.74 –2.09
Vested		(4.8	)		1.73 – 2.21		—			—		—		—
Forfeited		(3.0	)		1.73 – 2.21		(2.1	)		1.74 – 2.09		—		—
Exchanged		(9.2	)		—		—			—		—		—
Total nonvested at end of period		7.7			1.16 – 2.11		23.9			1.73 – 2.21		9.8		1.74 – 2.09

Other Share and Share-Based Awards — In 2008, we granted 2.4 million deferred share awards, each of which represents the right to receive one share of EFH Corp. stock, to certain management employees who agreed to forego share-based awards that vested at the Merger date. The deferred share awards are fully vested and are payable in cash or stock upon the earlier of a change of control or separation of service. No expense was recorded in 2008 related to these awards. An additional 1.2 million deferred share awards were granted to certain management employees in 2008, approximately half of which are payable in cash or stock and the balance payable in stock; these awards vest over periods of one to five years, and $3.7 million and $2.2 million in expense was recorded in 2009 and 2008, respectively, to recognize the vesting. In 2009, 120 thousand deferred share awards were surrendered by an employee upon termination of employment. Deferred share awards that are payable in cash or stock are accounted for as liability awards; therefore, the effects of changes in value of EFH Corp. shares are recognized in earnings.

F-72

We granted 1.5 million shares of EFH Corp. stock in 2009, 1.7 million shares in 2008 and 1.0 million shares in 2007, to board members and other non-employees. The shares vest over periods of one to two years, and a portion may be settled in cash. Expense recognized in 2009, 2008 and 2007 related to these grants totaled $4.0 million, $8.2 million and $1 million, respectively.

Stock Appreciation Rights — In 2008, Oncor established the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan (the SARs Plan) under which certain employees of Oncor and its subsidiaries may be granted stock appreciation rights (SARs) payable in cash, or in some circumstances, Oncor units. Two types of SARs may be granted under the SARs Plan. Time-based SARs (Time SARs) vest solely based upon continued employment ratably on an annual basis on each of the first five anniversaries of the grant date. Performance-based SARs (Performance SARs) vest based upon both continued employment and the achievement of a predetermined level of Oncor EBITDA over time, generally ratably over five years based upon annual Oncor EBITDA levels, with provisions for vesting if the annual levels are not achieved but cumulative two- or three-year total Oncor EBITDA levels are achieved. Time and Performance SARs may also vest in part or in full upon the occurrence of certain specified liquidity events and are exercisable only upon the occurrence of certain specified liquidity events. Since the exercisability of the Time and Performance SARs is conditioned upon the occurrence of a liquidity event, compensation expense will not be recorded until it is probable that a liquidity event will occur. Generally, awards under the SARs Plan terminate on the tenth anniversary of the grant, unless the participant’s employment is terminated earlier under certain circumstances.

In February 2009, Oncor implemented a similar plan for primarily non-employee members of Oncor’s board of directors. The terms and conditions are similar to the SARs Plan with the exception that SARs granted to non-employee board members vest in eight equal quarterly installments over a two-year period.

SARs are generally payable in cash based on the fair market value of the SAR on the date of exercise. No SARs were granted under the SARs Plan during the year ended December 31, 2009. Oncor granted 6.9 million Time SARs under the SARs Plan during the year ended December 31, 2008, and Time SARS vested at December 31, 2009 totaled 2.8 million. Oncor granted 6.9 million Performance SARs under the SARs Plan during the year ended December 31, 2008, and Performance SARs vested at December 31, 2009 totaled 1.4 million. Oncor granted 55 thousand SARs under the Director SARs Plan during the year ended December 31, 2009, and SARs vested under the Director SARs Plan at December 31, 2009 totaled 27.5 thousand. There were no SARs under either plan eligible for exercise at December 31, 2009.

Predecessor

Under our shareholder-approved long-term incentive plans, we provided discretionary awards to qualified management employees payable in EFH Corp. 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 EFH Corp.’s stock over the vesting period.

	Awards Granted in 2007
Vesting period	Three years
Potential share pay-out as a percent of initial number of awards granted	0% to 100% (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
Award type	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.

F-73

In addition, we 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 was based on the observed dividend payments over the twelve months prior to grant date.

• Risk-free rate (three-year US Treasury securities) during the three year vesting period.

• Discount for liquidation restrictions — this factor estimated the discount for lack of marketability of vested awards due to the anticipated time for the approval and issuance of the awards, the black-out period immediately after the grant and additional holding requirements imposed on senior executives. This discount was determined based on an estimation of the cost of a protective put at the award date and is calculated using the Black-Scholes option pricing model using expected volatility assumptions based on historical and implied volatility as discussed above and a risk-free rate of return over the option period.

• 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
Expected volatility	29% – 30%
Expected annual dividend	—
Risk-free rate	4.8% – 4.9%
Discount for liquidity restrictions	0% – 4.8%

The following table presents information about Predecessor stock-based compensation plans.

	Performance Unit Awards
Number of awards:
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 period from January 1, 2007 to October 10, 2007	$	67.08

The table above reflects the weighted average fair value of the awards on grant date.

Reported expense related to the awards totaled $27 million ($18 million after-tax) in the period from January 1, 2007 through October 10, 2007. 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 totaled $613 million based on the vesting date share prices.

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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.

23. RELATED PARTY TRANSACTIONS

We incur an annual management fee under the terms of a management agreement with the Sponsor Group for which we accrued $36 million, $35 million and $8 million for the years ended December 31, 2009 and 2008 and the period October 11, 2007 to December 31, 2007, respectively. The fee is reported as SG&A expense in Corporate and Other activities. Also, under terms of 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 was included in the purchase price that was allocated to identifiable assets and liabilities as part of purchase accounting, and the remainder was reported as deferred financing costs.

At the closing of the Merger, TCEH entered into the TCEH Senior Secured Facilities and Oncor entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of GS Capital Partners and Kohlberg Kravis Roberts & Co. L.P. (a member of the Sponsor Group) have from time to time engaged in commercial banking and financial advisory transactions with us in the normal course of business.

Affiliates of the Sponsor Group participated in debt exchange offers completed in November 2009 by EFH Corp., Intermediate Holding and EFIH Finance to exchange new senior secured notes for certain EFH Corp. and TCEH notes as discussed in Note 12 and in an EFH Corp. issuance of $500 million principal amount of senior secured notes completed in January 2010. Goldman, Sachs & Co. and KKR Capital Markets LLC acted as dealer managers and TPG Capital, L.P. served as an advisor in the exchange offers. Goldman, Sachs & Co. also acted as an initial purchaser in the issuance of senior secured notes. (See Note 12 for additional information.) These affiliates were compensated for their services in accordance with the terms of the respective agreements. These fees totaled $1 million for the year ended December 31, 2009.

Affiliates of Goldman Sachs & Co. are parties to certain commodity and interest rate hedging transactions with us in the normal course of business.

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

24. SEGMENT INFORMATION

Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.

The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, 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 by TCEH. The results of this segment also include equipment salvage and resale activities related to the 2007 cancellation of the development of eight new coal-fueled generation units discussed in Note 4.

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.

Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued operations, general corporate expenses and interest on EFH Corp., Intermediate Holding and EFC Holdings debt.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. We evaluate performance based on income from continuing operations. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.

F-75

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Operating Revenues
Competitive Electric	$	7,911		$	9,787		$	1,671		$	6,884
Regulated Delivery		2,690			2,580			532			1,987
Corp. and Other		20			37			11			37
Eliminations		(1,075	)		(1,040	)		(220	)		(864	)
Consolidated	$	9,546		$	11,364		$	1,994		$	8,044
Regulated Revenues — Included in Operating Revenues
Competitive Electric	$	—		$	—		$	—		$	—
Regulated Delivery		2,690			2,580			532			1,987
Corp. and Other		—			—			—			—
Eliminations		(1,051	)		(1,001	)		(208	)		(824	)
Consolidated	$	1,639		$	1,579		$	324		$	1,163
Affiliated Revenues — Included in Operating Revenues
Competitive Electric	$	8		$	7		$	2		$	5
Regulated Delivery		1,051			1,001			208			824
Corp. and Other		16			32			10			35
Eliminations		(1,075	)		(1,040	)		(220	)		(864	)
Consolidated	$	—		$	—		$	—		$	—
Depreciation and Amortization
Competitive Electric	$	1,172		$	1,092		$	315		$	253
Regulated Delivery		557			492			96			366
Corp. and Other		25			26			4			15
Eliminations		—			—			—			—
Consolidated	$	1,754		$	1,610		$	415		$	634
Equity in Earnings (Losses) of Unconsolidated Subsidiaries (a)
Competitive Electric	$	(7	)	$	(10	)	$	(2	)	$	(5	)
Regulated Delivery		(2	)		(4	)		(1	)		(2	)
Corp. and Other		(3	)		(5	)		(1	)		(4	)
Eliminations		12			19			4			10
Consolidated	$	—		$	—		$	—		$	(1	)
Interest Income
Competitive Electric	$	64		$	61		$	10		$	271
Regulated Delivery		43			45			12			44
Corp. and Other		147			100			42			106
Eliminations		(209	)		(179	)		(40	)		(365	)
Consolidated	$	45		$	27		$	24		$	56
Interest Expense and Related Charges
Competitive Electric	$	1,946		$	4,010		$	609		$	357
Regulated Delivery		346			317			70			242
Corp. and Other		829			787			200			437
Eliminations		(209	)		(179	)		(40	)		(365	)
Consolidated	$	2,912		$	4,935		$	839		$	671
Income Tax Expense (Benefit)
Competitive Electric	$	407		$	(450	)	$	(656	)	$	306
Regulated Delivery		173			221			30			160
Corp. and Other		(213	)		(242	)		(47	)		(157	)
Eliminations		—			—			—			—
Consolidated	$	367		$	(471	)	$	(673	)	$	309
Income (loss) from Continuing Operations
Competitive Electric	$	631		$	(8,929	)	$	(1,245	)	$	722
Regulated Delivery		320			(486	)		63			265
Corp. and Other		(543	)		(583	)		(179	)		(288	)
Eliminations		—			—			—			—

F-76

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Consolidated	$	408		$	(9,988	)	$	(1,361	)	$	699
Investment in Equity Investees
Competitive Electric	$	42		$	(2	)	$	(1	)
Regulated Delivery		—			—			—
Corp. and Other		—			—			—
Eliminations		—			—			—
Consolidated	$	42		$	(2	)	$	(1	)
Total assets (b)
Competitive Electric	$	43,302		$	43,061		$	49,297
Regulated Delivery		16,246			15,772			15,458
Corp. and Other		4,355			3,526			2,992
Eliminations		(4,241	)		(3,096	)		(2,943	)
Consolidated	$	59,662		$	59,263		$	64,804
Capital Expenditures
Competitive Electric	$	1,324		$	1,914		$	530		$	1,901
Regulated Delivery		998			919			162			580
Corp. and Other		26			16			1			7
Eliminations		—			—			—			—
Consolidated	$	2,348		$	2,849		$	693		$	2,488

(a) Amounts invested in equity investee were not material in any period presented.

(b) Assets by segment exclude investments in affiliates.

25. SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Operating revenues
Regulated	$	2,690		$	2,580		$	532		$	1,987
Unregulated		7,931			9,824			1,682			6,921
Intercompany sales eliminations — regulated		(1,051	)		(1,001	)		(208	)		(824	)
Intercompany sales eliminations — unregulated		(24	)		(39	)		(12	)		(40	)
Total operating revenues		9,546			11,364			1,994			8,044
Fuel, purchased power and delivery fees — unregulated (a)		(2,878	)		(4,595	)		(644	)		(2,381	)
Net gain (loss) from commodity hedging and trading activities — unregulated		1,736			2,184			(1,492	)		(554	)
Operating costs — regulated		(908	)		(828	)		(182	)		(637	)
Operating costs — unregulated		(690	)		(675	)		(124	)		(470	)
Depreciation and amortization — regulated		(557	)		(492	)		(96	)		(366	)
Depreciation and amortization — unregulated		(1,197	)		(1,118	)		(319	)		(268	)
Selling, general and administrative expenses — regulated		(194	)		(164	)		(45	)		(134	)
Selling, general and administrative expenses — unregulated		(874	)		(793	)		(171	)		(557	)
Franchise and revenue-based taxes — regulated		(250	)		(255	)		(62	)		(198	)
Franchise and revenue-based taxes — unregulated		(109	)		(108	)		(31	)		(84	)
Impairment of goodwill		(90	)		(8,860	)		—			—
Other income		204			80			14			69
Other deductions		(97	)		(1,301	)		(61	)		(841	)
Interest income		45			27			24			56
Interest expense and other charges		(2,912	)		(4,935	)		(839	)		(671	)
Income (loss) from continuing operations before income taxes	$	775		$	(10,469	)	$	(2,034	)	$	1,008

F-77

(a) Includes unregulated cost of fuel consumed of $1.269 billion in 2009, $1.604 billion in 2008, $255 million in the period from October 11, 2007 through December 31, 2007 and $868 million in the period from January 1, 2007 through October 10, 2007. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.

Interest Expense and Related Charges

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)	$	3,479		$	3,482		$	800		$	722
Unrealized mark-to-market net (gain) loss on interest rate swaps		(696	)		1,477			—			—
Amortization of interest rate swap losses at dedesignation of hedge accounting		184			66			—			10
Amortization of fair value debt discounts resulting from purchase accounting		82			75			17			—
Amortization of debt issuance costs and discounts		140			146			81			19
Capitalized interest, primarily related to generation facility and regulated utility asset construction		(277	)		(311	)		(59	)		(80	)
Total interest expense and related charges	$	2,912		$	4,935		$	839		$	671

Restricted Cash

	Successor
	At December 31, 2009				At December 31, 2008
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to TCEH’s Letter of Credit Facility (See Note 12)	$	—	$	1,135	$	—	$	1,250
Amounts related to margin deposits held		1		—		4		—
Amounts related to securitization (transition) bonds		47		14		51		17
Total restricted cash	$	48	$	1,149	$	55	$	1,267

Inventories by Major Category

	Successor
	December 31, 2009		December 31, 2008
Materials and supplies	$	248	$	199
Fuel stock		204		162
Natural gas in storage		33		65
Total inventories	$	485	$	426

F-78

Property, Plant and Equipment

	Successor
	December 31, 2009		December 31, 2008
Competitive Electric:
Generation and mining	$	20,755	$	16,954
Nuclear fuel (net of accumulated amortization of $426 and $235)		430		433
Other assets		27		16
Regulated Delivery:
Transmission		3,917		3,626
Distribution		8,778		8,429
Other assets		174		166
Corporate and Other		161		138
Total		34,242		29,762
Less accumulated depreciation		6,633		5,321
Net of accumulated depreciation		27,609		24,441
Construction work in progress:
Competitive Electric		2,163		4,852
Regulated Delivery		321		213
Corporate and Other		15		16
Total construction work in progress		2,499		5,081
Property, plant and equipment — net	$	30,108	$	29,522

Depreciation expense totaled $1.454 billion, $1.355 billion, $297 million and $467 million for the years ended December 31, 2009 and 2008, the period October 11, 2007 through December 31, 2007 and the period January 1, 2007 through October 10, 2007, respectively, including $394 million, $330 million, $63 million and $235 million, respectively, related to Oncor.

We began depreciating two recently completed lignite-fueled generation units in the fourth quarter 2009.

Assets related to capitalized leases included above totaled $167 million at both December 31, 2009 and 2008, 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.

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, 2009 and 2008:

Asset retirement liability at January 1, 2008	$	773
Additions:
Accretion		48
Incremental mining reclamation costs		59
Reductions:
Payments, essentially all mining reclamation		(21	)
Asset retirement liability at December 31, 2008	$	859
Additions:
Accretion		59
Incremental mining reclamation costs		59
Reductions:
Payments, essentially all mining reclamation		(29	)
Asset retirement liability at December 31, 2009	$	948

Oncor’s Regulatory Assets and Liabilities

Recognition of regulatory assets and liabilities and the amortization periods over which they are expected to be recovered or refunded through rate regulation reflect the decisions of the PUCT. Components of the regulatory assets and liabilities are provided in the table below. Amounts not earning a return through rate regulation are noted. On August 31, 2009, the PUCT issued a final order on Oncor’s rate review filed in June 2008. The rate review included a determination of the recoverability of regulatory assets as of December 31, 2007, including the recoverability period of those assets deemed allowable by the PUCT. The PUCT’s findings included denial of recovery of certain regulatory assets primarily related to business restructuring costs and rate case expenses, which resulted in a $25 million charge ($16 million after-tax) in the third quarter 2009 reported in other deductions in the Regulated Delivery segment.

F-79

	Remaining Rate Recovery/Amortization Period as of December 31, 2009		Carrying Amount
			December 31, 2009		December 31, 2008
Regulatory assets:
Generation-related regulatory assets securitized by transition bonds (a)		7 years	$	759	$	865
Employee retirement costs		5 years		80		—
Employee retirement costs to be reviewed (b)(c)		To be determined		41		100
Employee retirement liability (a)(c)(d)		To be determined		768		559
Self-insurance reserve (primarily storm recovery costs) — net		7 years		137		—
Self-insurance reserve to be reviewed (b)(c)		To be determined		106		214
Nuclear decommissioning cost under-recovery (a)(c)(e)		Not applicable		85		127
Securities reacquisition costs (pre-industry restructure)		8 years		62		68
Securities reacquisition costs (post-industry restructure)		Terms of related debt		27		29
Recoverable amounts for/in lieu of deferred income taxes — net		Life of related asset or liability		68		77
Rate case expenses (f)		Largely 3 years		9		10
Rate case expenses to be reviewed (b)(c)		To be determined		1		—
Advanced meter customer education costs		10 years		4		2
Deferred conventional meter depreciation		10 years		14		—
Energy efficiency performance bonus		1 year		9		—
Business restructuring costs (g)		Not applicable		—		20
Total regulatory assets				2,170		2,071
Regulatory liabilities:
Committed spending for demand-side management initiatives (a)		3 years		78		96
Deferred advanced metering system revenues		10 years		57		—
Investment tax credit and protected excess deferred taxes		Various		44		49
Over-collection of securitization (transition) bond revenues (a)		7 years		27		28
Other regulatory liabilities (a)		Various		5		6
Total regulatory liabilities				211		179
Net regulatory asset			$	1,959	$	1,892

(a) Not earning a return in the regulatory rate-setting process.

(b) Costs incurred since the period covered under the last rate review.

(c) Recovery is specifically authorized by statute, subject to reasonableness review by the PUCT.

(d) Represents unfunded liabilities recorded in accordance with pension and OPEB accounting standards.

(e) Offset by an intercompany payable to TCEH.

(f) Rate case expenses totaling $4 million were disallowed by the PUCT and written off in the third quarter of 2009.

(g) All previously recorded business restructuring costs were disallowed by the PUCT and written off in the third quarter of 2009.

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.

In September 2008, the PUCT approved a settlement for Oncor to recover its estimated future investment for advanced metering deployment. Oncor began billing the advanced metering surcharge in the January 2009 billing month cycle. The surcharge is expected to total $1.023 billion over the 11-year recovery period and includes a cost recovery factor of $2.19 per month per residential retail customer and $2.39 to $5.15 per month for non-residential retail customers. We account for the difference between the surcharge billings for advanced metering facilities and the allowed revenues under the surcharge provisions, which are based on expenditures and an allowed return, as a regulatory asset or liability. Such differences arise principally as a result of timing of expenditures. As indicated in the table above, the regulatory liability at December 31, 2009 totaled $57 million.

F-80

See Note 6 for discussion of effects on regulatory assets and liabilities of the stipulation approved by the PUCT and Note 19 for additional information regarding nuclear decommissioning cost recovery.

Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:

	Successor
	December 31, 2009		December 31, 2008
Uncertain tax positions (including accrued interest) (Note 8)	$	1,999	$	1,780
Retirement plan and other employee benefits		1,711		1,451
Asset retirement obligations		948		859
Unfavorable purchase and sales contracts		700		727
Liabilities related to subsidiary tax sharing agreement		321		299
Other		87		89
Total other noncurrent liabilities and deferred credits	$	5,766	$	5,205

Unfavorable Purchase and Sales Contracts — Unfavorable purchase and sales contracts primarily represent the extent to which contracts on a net basis were unfavorable to market prices as of the date of the Merger. These are contracts for which: (i) TCEH has made the “normal” purchase or sale election allowed or (ii) the contract did not meet the definition of a derivative under accounting standards related to derivative instruments and hedging transactions. Under purchase accounting, TCEH recorded the value as of October 10, 2007 as a deferred credit. Amortization of the deferred credit related to unfavorable contracts is primarily on a straight-line basis, which approximates the economic realization, and is recorded as revenues or a reduction of purchased power costs as appropriate. The amortization amount totaled $27 million and $30 million in 2009 and 2008, respectively, and $5 million in the 2007 Successor period. Favorable purchase and sales contracts are recorded as intangible assets (see Note 3).

The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:

Year	Amount
2010	$	27
2011		27
2012		27
2013		26
2014		25

Liabilities Related to Subsidiary Tax Sharing Agreement — Amount represents the previously recorded net deferred tax liabilities of Oncor related to the noncontrolling interests. Upon the sale of noncontrolling interests in Oncor (see Note 15), Oncor became a partnership for US federal income tax purposes, and the temporary differences which gave rise to the deferred taxes will, over time, become taxable to the noncontrolling interests. Under a tax sharing agreement among Oncor and its equity holders, Oncor reimburses the equity holders for federal income taxes as the partnership earnings become taxable to such holders. Accordingly, as the temporary differences become taxable, the equity holders will be reimbursed by Oncor. In the unlikely event such amounts are not reimbursed under the tax sharing agreement, it is probable they would be refunded to rate payers. The net changes in the liability for the year ended December 31, 2009 totaling $22 million reflected changes in temporary differences.

F-81

Supplemental Cash Flow Information

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Cash payments (receipts) related to continuing operations:
Interest paid (a)	$	2,972		$	3,495		$	496		$	674
Capitalized interest		(277	)		(311	)		(59	)		(80	)
Interest paid (net of capitalized interest) (a)		2,695			3,184			437			594
Income taxes		(42	)		(204	)		—			271
Noncash investing and financing activities:
Debt exchange transaction (Note 12)		(101	)		—			—			—
Below market values of power sales agreements (b)		—			—			—			264
Noncash construction expenditures (c)		197			183			211			210
Promissory note issued in conjunction with acquisition of mining-related assets		—			—			—			65
Capital leases		15			16			—			52
Noncash capital contribution from Texas Holdings		—			—			23			—

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

(b) 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.

(c) Represents end-of-period accruals.

26. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

In 2007, EFH Corp. issued $2.0 billion EFH Corp. 10.875% Notes and $2.5 billion EFH Corp. Toggle Notes (collectively, the EFH Corp. Senior Notes). In May 2009 and November 2009, EFH Corp. issued an additional $150 million and $159 million, respectively, of the EFH Corp. Toggle Notes. In November 2009, EFH Corp. issued $115 million EFH Corp. 9.75% Notes in exchange for certain outstanding debt securities (see Note 12). The EFH Corp. Senior Notes and 9.75% Notes are unconditionally guaranteed by EFC Holdings and Intermediate Holding, 100% owned subsidiaries of EFH Corp. (collectively, the Guarantors) on an unsecured basis except for the Intermediate Holding guarantee of the EFH Corp. 9.75% Notes, which is secured by a pledge of all membership interests and other investments Intermediate Holding owns or holds in Oncor Holdings or any of Oncor Holdings’ subsidiaries as described in Note 12. The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the EFH Corp. Senior Notes and 9.75% Notes. The guarantees by EFC Holdings and the guarantee of the EFH Corp. Senior Notes by Intermediate Holding 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. Senior Notes and 9.75% Notes (collectively, the Non-Guarantors). The indentures governing the EFH Corp. Senior Notes and 9.75% Notes contain certain restrictions, subject to certain exceptions, on EFH Corp.’s ability to pay dividends or make investments. See Note 12.

The following tables have been prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered” in order to present the condensed consolidating statements of income and cash flows of EFH Corp. (the Parent/Issuer), the Guarantors and the Non-Guarantors for the years ended December 31, 2009 and 2008, the period from October 11, 2007 through December 31, 2007 and the period from January 1, 2007 through October 10, 2007 and the consolidating balance sheets as of December 31, 2009 and 2008 of the Parent/Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5-J, “Push Down Basis of Accounting Required in Certain Limited Circumstances”, including the effects of the push down of the $4.63 billion and $4.5 billion principal amount of EFH Corp. Senior Notes as of December 31, 2009 and 2008, respectively, and the $115 million principal amount of the EFH Corp. 9.75% Notes as of December 31, 2009 to the Guarantors (see Notes 12 and 13).

EFH Corp. (Parent) received dividends from its consolidated subsidiaries totaling $216 million, $329 million and $1.461 billion for the years ended December 31, 2009 and 2008 and the Predecessor period from January 1, 2007 through October 10, 2007, respectively. EFH Corp. also received a distribution of $1.253 billion indirectly from Oncor as discussed in Note 15. No dividends were received during the period from October 11, 2007 through December 31, 2007. See Note 14.

F-82

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Year Ended December 31, 2009

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	9,546		$	—		$	9,546
Fuel, purchased power costs and delivery fees		—			—			(2,878	)		—			(2,878	)
Net gain from commodity hedging and trading activities		—			—			1,736			—			1,736
Operating costs		—			—			(1,598	)		—			(1,598	)
Depreciation and amortization		—			—			(1,754	)		—			(1,754	)
Selling, general and administrative expenses		(123	)		—			(945	)		—			(1,068	)
Franchise and revenue-based taxes		—			—			(359	)		—			(359	)
Impairment of goodwill		—			—			(90	)		—			(90	)
Other income		49			—			114			41			204
Other deductions		(6	)		—			(91	)		—			(97	)
Interest income		235			5			149			(344	)		45
Interest expense and related charges		(981	)		(570	)		(2,258	)		897			(2,912	)
Income (loss) from continuing operations before income taxes and equity earnings of subsidiaries		(826	)		(565	)		1,572			594			775
Income tax (expense) benefit		268			188			(622	)		(201	)		(367	)
Equity earnings of subsidiaries		902			965			—			(1,867	)		—
Net income (loss)		344			588			950			(1,474	)		408
Net income attributable to noncontrolling interests		—			—			(64	)		—			(64	)
Net income (loss) attributable to EFH Corp.	$	344		$	588		$	886		$	(1,474	)	$	344

F-83

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Year Ended December 31, 2008

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	11,364		$	—		$	11,364
Fuel, purchased power costs and delivery fees		—			—			(4,595	)		—			(4,595	)
Net gain from commodity hedging and trading activities		—			—			2,184			—			2,184
Operating costs		—			—			(1,503	)		—			(1,503	)
Depreciation and amortization		—			—			(1,610	)		—			(1,610	)
Selling, general and administrative expenses		(105	)		—			(852	)		—			(957	)
Franchise and revenue-based taxes		—			1			(364	)		—			(363	)
Impairment of goodwill		—			—			(8,860	)		—			(8,860	)
Other income		—			—			80			—			80
Other deductions		(22	)		—			(1,279	)		—			(1,301	)
Interest income		168			7			147			(295	)		27
Interest expense and related charges		(919	)		(537	)		(4,298	)		819			(4,935	)
Income (loss) from continuing operations before income taxes and equity earnings of subsidiaries		(878	)		(529	)		(9,586	)		524			(10,469	)
Income tax (expense) benefit		291			180			176			(176	)		471
Equity earnings of subsidiaries		(9,251	)		(9,184	)		—			18,435			—
Net loss		(9,838	)		(9,533	)		(9,410	)		18,783			(9,998	)
Net loss attributable to noncontrolling interests		—			—			160			—			160
Net loss attributable to EFH Corp.	$	(9,838	)	$	(9,533	)	$	(9,250	)	$	18,783		$	(9,838	)

F-84

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Period from October 11, 2007 through December 31, 2007

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	1,994		$	—		$	1,994
Fuel, purchased power costs and delivery fees		—			—			(644	)		—			(644	)
Net loss from commodity hedging and trading activities		—			—			(1,492	)		—			(1,492	)
Operating costs		—			—			(306	)		—			(306	)
Depreciation and amortization		—			—			(416	)		1			(415	)
Selling, general and administrative expenses		(17	)		—			(198	)		(1	)		(216	)
Franchise and revenue-based taxes		(1	)		—			(92	)		—			(93	)
Other income		—			—			14			—			14
Other deductions		(54	)		—			(7	)		—			(61	)
Interest income		54			6			32			(68	)		24
Interest expense and related charges		(234	)		(140	)		(670	)		205			(839	)
Loss from continuing operations before income taxes and equity earnings of subsidiaries		(252	)		(134	)		(1,785	)		137			(2,034	)
Income tax benefit		53			28			637			(45	)		673
Equity earnings of subsidiaries		(1,161	)		(1,142	)		—			2,303			—
Loss from continuing operations		(1,360	)		(1,248	)		(1,148	)		2,395			(1,361	)
Income from discontinued operations, net of tax effect		—			—			1			—			1
Net loss attributable to EFH Corp.	$	(1,360	)	$	(1,248	)	$	(1,147	)	$	2,395		$	(1,360	)

F-85

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Period from January 1, 2007 through October 10, 2007

(millions of dollars)

	Predecessor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	8,044		$	—		$	8,044
Fuel, purchased power costs and delivery fees		—			—			(2,381	)		—			(2,381	)
Net loss from commodity hedging and trading activities		—			—			(554	)		—			(554	)
Operating costs		—			—			(1,107	)		—			(1,107	)
Depreciation and amortization		—			—			(634	)		—			(634	)
Selling, general and administrative expenses		(58	)		—			(633	)		—			(691	)
Franchise and revenue-based taxes		—			(1	)		(282	)		1			(282	)
Other income		8			1			60			—			69
Other deductions		(108	)		—			(733	)		—			(841	)
Interest income		133			210			368			(655	)		56
Interest expense and related charges		(566	)		(192	)		(567	)		654			(671	)
Income (loss) from continuing operations before income taxes and equity earnings of subsidiaries		(591	)		18			1,581			—			1,008
Income tax (expense) benefit		235			(2	)		(542	)		—			(309	)
Equity earnings of subsidiaries		1,077			1,554			—			(2,631	)		—
Income from continuing operations		721			1,570			1,039			(2,631	)		699
Income from discontinued operations, net of tax effect		2			—			22			—			24
Net income attributable to EFH Corp.	$	723		$	1,570		$	1,061		$	(2,631	)	$	723

F-86

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2009

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(42	)	$	208		$	1,977		$	(432	)	$	1,711
Cash flows — financing activities:
Issuances of long-term borrowings		—			—			522			—			522
Retirements of long-term borrowings		(4	)		(7	)		(385	)		—			(396	)
Change in short-term borrowings		—			—			332			—			332
Contributions from noncontrolling interests		—			—			48			—			48
Distributions paid to noncontrolling interests		—			—			(56	)		—			(56	)
Cash dividends paid		—			(216	)		(216	)		432			—
Change in advances — affiliates		425			15			—			(440	)		—
Other, net		5			—			(33	)		—			(28	)
Cash provided by (used in) financing activities		426			(208	)		212			(8	)		422
Cash flows — investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(2,545	)		—			(2,545	)
Money market fund redemptions		—			—			142			—			142
Investment posted with derivative counterparty		(400	)		—			—			—			(400	)
Net proceeds from sale of majority interest in natural gas gathering pipeline business		—			—			40			—			40
Reduction of restricted cash related to letter of credit facility		—			—			115			—			115
Proceeds from sale of environmental allowances and credits		—			—			19			—			19
Purchases of environmental allowances and credits		—			—			(19	)		—			(19	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			3,064			—			3,064
Investments in nuclear decommissioning trust fund securities		—			—			(3,080	)		—			(3,080	)
Change in advances — affiliates		—			—			(440	)		440			—
Other, net		—			—			31			—			31
Cash provided by (used in) investing activities		(400	)		—			(2,673	)		440			(2,633	)
Net change in cash and cash equivalents		(16	)		—			(484	)		—			(500	)
Cash and cash equivalents — beginning balance		1,075			—			614			—			1,689
Cash and cash equivalents — ending balance	$	1,059		$	—		$	130		$	—		$	1,189

F-87

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2008

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(251	)	$	(924	)	$	832		$	1,848		$	1,505
Cash flows — financing activities:
Issuances of securities/long-term borrowings:
Long-term debt		—			—			3,185			—			3,185
Common stock		34			—			—			—			34
Retirements/repurchases of securities/long-term borrowings:
Long-term debt		(200	)		(7	)		(960	)		—			(1,167	)
Common stock		(3	)		—			—			—			(3	)
Change in short-term borrowings		—			—			(481	)		—			(481	)
Proceeds from sale of noncontrolling interests, net of transaction costs		1,253			1,253			1,253			(2,506	)		1,253
Cash dividends paid		—			(329	)		(329	)		658			—
Change in advances — affiliates		205			7			—			(212	)		—
Other, net		—			—			16			—			16
Cash provided by (used in) financing activities		1,289			924			2,684			(2,060	)		2,837
Cash flows — investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(2,978	)		—			(2,978	)
Investments held in money market fund		—			—			(142	)		—			(142	)
Proceeds from sale of environmental allowances and credits		—			—			39			—			39
Purchases of environmental allowances and credits		—			—			(34	)		—			(34	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			1,623			—			1,623
Investments in nuclear decommissioning trust fund securities		—			—			(1,639	)		—			(1,639	)
Change in advances — affiliates		—			—			(212	)		212			—
Other, net		5			—			192			—			197
Cash provided by (used in) investing activities		5			—			(3,151	)		212			(2,934	)
Net change in cash and cash equivalents		1,043			—			365			—			1,408
Cash and cash equivalents — beginning balance		32			—			249			—			281
Cash and cash equivalents — ending balance	$	1,075		$	—		$	614		$	—		$	1,689

F-88

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 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-89

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 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-90

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at December 31, 2009

(millions of dollars)

	Successor
	Parent/Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	1,059	$	—	$	130	$	—		$	1,189
Investment posted with counterparty		425		—		—		—			425
Restricted cash		—		—		48		—			48
Advances to affiliates		471		5		—		(476	)		—
Trade accounts receivable — net		8		2		1,253		(3	)		1,260
Income taxes receivable		23		2		—		(25	)		—
Accounts receivable from affiliates		—		—		22		(22	)		—
Notes receivable from affiliates		114		—		1,469		(1,583	)		—
Inventories		—		—		485		—			485
Commodity and other derivative contractual assets		52		—		2,339		—			2,391
Accumulated deferred income taxes		—		3		11		(9	)		5
Margin deposits related to commodity positions		—		—		187		—			187
Other current assets		2		—		134		—			136
Total current assets		2,154		12		6,078		(2,118	)		6,126
Restricted cash		—		—		1,149		—			1,149
Investments		4,586		3,634		682		(8,152	)		750
Property, plant and equipment — net		—		—		30,108		—			30,108
Notes receivable from affiliates		12		—		2,236		(2,248	)		—
Goodwill		—		—		14,316		—			14,316
Intangible assets — net		—		—		2,876		—			2,876
Regulatory assets — net		—		—		1,959		—			1,959
Commodity and other derivative contractual assets		—		—		1,533		—			1,533
Accumulated deferred income taxes		647		111		—		(758	)		—
Unamortized debt issuance costs and other noncurrent assets		108		99		733		(95	)		845
Total assets	$	7,507	$	3,856	$	61,670	$	(13,371	)	$	59,662
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—	$	—	$	1,569	$	—		$	1,569
Advances from affiliates		—		—		476		(476	)		—
Long-term debt due currently		—		8		409		—			417
Trade accounts payable		4		—		892		—			896
Accounts payable to affiliates		16		6		—		(22	)		—
Notes payable to affiliates		1,406		27		150		(1,583	)		—
Commodity and other derivative contractual liabilities		82		—		2,310		—			2,392
Margin deposits related to commodity positions		—		—		520		—			520
Accumulated deferred income taxes		9		—		—		(9	)		—
Accrued interest		119		93		408		(94	)		526
Other current liabilities		7		—		761		(24	)		744
Total current liabilities		1,643		134		7,495		(2,208	)		7,064
Accumulated deferred income taxes		—		—		6,764		(633	)		6,131
Investment tax credits		—		—		37		—			37
Commodity and other derivative contractual liabilities		—		—		1,060		—			1,060
Notes or other liabilities due affiliates		2,019		—		229		(2,248	)		—
Long-term debt, less amounts due currently		6,626		4,975		34,740		(4,901	)		41,440
Other noncurrent liabilities and deferred credits		466		3		5,297		—			5,766
Total liabilities		10,754		5,112		55,622		(9,990	)		61,498

F-91

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets (Cont’d)

at December 31, 2009

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
EFH Corp. shareholders’ equity		(3,247	)		(1,256	)		4,637		(3,381	)		(3,247	)
Noncontrolling interests in subsidiaries		—			—			1,411		—			1,411
Total equity		(3,247	)		(1,256	)		6,048		(3,381	)		(1,836	)
Total liabilities and equity	$	7,507		$	3,856		$	61,670	$	(13,371	)	$	59,662

F-92

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at December 31, 2008

(millions of dollars)

	Successor
	Parent/Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	1,075		$	—		$	614	$	—		$	1,689
Investments held in money market fund		—			—			142		—			142
Restricted cash		—			—			55		—			55
Advances to affiliates		403			7			—		(410	)		—
Trade accounts receivable — net		3			—			1,216		—			1,219
Income taxes receivable		—			—			128		(86	)		42
Accounts receivable from affiliates		—			—			3		(3	)		—
Notes receivable from affiliates		—			—			633		(633	)		—
Inventories		—			—			426		—			426
Commodity and other derivative contractual assets		143			—			2,391		—			2,534
Accumulated deferred income taxes		—			—			80		(36	)		44
Margin deposits related to commodity positions		—			—			439		—			439
Other current assets		6			—			159		—			165
Total current assets		1,630			7			6,286		(1,168	)		6,755
Restricted cash		—			—			1,267		—			1,267
Investments		3,758			2,652			579		(6,344	)		645
Property, plant and equipment — net		—			—			29,522		—			29,522
Notes receivable from affiliates		12			—			2,273		(2,285	)		—
Goodwill		—			—			14,386		—			14,386
Intangible assets — net		—			—			2,993		—			2,993
Regulatory assets — net		—			—			1,892		—			1,892
Commodity and other derivative contractual assets		—			—			962		—			962
Accumulated deferred income taxes		575			6			—		(581	)		—
Unamortized debt issuance costs and other noncurrent assets		130			111			711		(111	)		841
Total assets	$	6,105		$	2,776		$	60,871	$	(10,489	)	$	59,263
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	—		$	1,237	$	—		$	1,237
Advances from affiliates		—			—			410		(410	)		—
Long-term debt due currently		3			8			374		—			385
Trade accounts payable		8			—			1,135		—			1,143
Accounts payable to affiliates		—			3			—		(3	)		—
Notes payable to affiliates		585			13			35		(633	)		—
Commodity and other derivative contractual liabilities		178			—			2,730		—			2,908
Margin deposits related to commodity positions		—			—			525		—			525
Accumulated deferred income taxes		36			—			—		(36	)		—
Accrued interest		110			87			413		(86	)		524
Other current liabilities		111			—			587		(86	)		612
Total current liabilities		1,031			111			7,446		(1,254	)		7,334
Accumulated deferred income taxes		—			—			6,648		(581	)		6,067
Investment tax credits		—			—			42		—			42
Commodity and other derivative contractual liabilities		—			—			2,095		—			2,095
Notes or other liabilities due affiliates		2,019			—			266		(2,285	)		—
Long-term debt, less amounts due currently		6,340			4,597			34,401		(4,500	)		40,838
Other noncurrent liabilities and deferred credits		388			1			4,817		(1	)		5,205
Total liabilities		9,778			4,709			55,715		(8,621	)		61,581
EFH Corp. shareholders’ equity		(3,673	)		(1,933	)		3,801		(1,868	)		(3,673	)
Noncontrolling interests in subsidiaries		—			—			1,355		—			1,355
Total equity		(3,673	)		(1,933	)		5,156		(1,868	)		(2,318	)
Total liabilities and equity	$	6,105		$	2,776		$	60,871	$	(10,489	)	$	59,263

F-93

GLOSSARY

When the following terms and abbreviations appear in the text of these financial statements, they have the meanings indicated below.

2009 Form 10-K EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2009

Adjusted EBITDA Adjusted EBITDA means EBITDA adjusted to exclude non-cash items, unusual items and other adjustments allowable under certain of our debt arrangements. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA elsewhere herein (see reconciliations in “Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for the Three and Nine Months Ended September 30, 2010 — Covenants and Restrictions Under Financing Arrangements”) solely because of the important role that Adjusted EBITDA plays in respect of the certain covenants contained in our debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.

baseload Refers to the minimum constant level of electricity demand in a system, such as ERCOT, and/or to the electricity generation facilities or capacity normally expected to operate continuously throughout the year to serve such demand, such as our nuclear and lignite/coal-fueled generation units.

Competitive Electric segment Refers to the EFH Corp. business segment that consists principally of TCEH.

CREZ Competitive Renewable Energy Zone

EBITDA Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. See the definition of Adjusted EBITDA above.

EFCH Refers to Energy Future Competitive Holdings Company, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of TCEH, and/or its subsidiaries, depending on context.

EFH Corp. Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include TCEH and Oncor.

EFH Corp. Senior Notes Refers collectively to EFH Corp.’s 10.875% Senior Notes due November 1, 2017 (EFH Corp. 10.875% Notes) and EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes).

EFH Corp. Senior Secured Notes Refers collectively to EFH Corp.’s 9.75% Senior Secured Notes due October 15, 2019 (EFH Corp. 9.75% Notes) and EFH Corp.’s 10.000% Senior Secured Notes due January 15, 2020 (EFH Corp. 10% Notes).

F-94

EFIH Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.

EFIH Finance Refers to EFIH Finance Inc., a direct, wholly-owned subsidiary of EFIH, formed for the sole purpose of serving as co-issuer with EFIH of certain debt securities.

EFIH Notes Refers collectively to EFIH’s and EFIH Finance’s 9.75% Senior Secured Notes due October 15, 2019 (EFIH 9.75% Notes) and EFIH’s and EFIH Finance’s 10.000% Senior Secured Notes due December 1, 2020 (EFIH 10% Notes).

EPA US Environmental Protection Agency

EPC engineering, procurement and construction

ERCOT Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas

FASB Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting

FERC US Federal Energy Regulatory Commission

Fitch Fitch Ratings, Ltd. (a credit rating agency)

GAAP generally accepted accounting principles

GHG greenhouse gas

GWh gigawatt-hours

kWh kilowatt-hours

Lehman Refers to certain subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code in 2008.

LIBOR London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market.

Luminant Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.

market heat rate Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.

Merger The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007.

F-95

Merger Agreement Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.

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

NRC US Nuclear Regulatory Commission

NYMEX Refers to the New York Mercantile Exchange, a physical commodity futures exchange.

Oncor Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities.

Oncor Holdings Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context.

Oncor Ring-Fenced Entities Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor.

OPEB other postretirement employee benefits

PUCT Public Utility Commission of Texas

PURA Texas Public Utility Regulatory Act

purchase accounting The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.

Regulated Delivery segment Refers to the EFH Corp. business segment that consists of the operations of Oncor.

REP retail electric provider

RRC Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas

S&P Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies Inc. (a credit rating agency)

SEC US Securities and Exchange Commission

Securities Act Securities Act of 1933, as amended

SG&A selling, general and administrative

Sponsor Group Refers collectively to the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P. (KKR), TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman, Sachs & Co. (See Texas Holdings below.)

F-96

TCEH Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of EFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy markets activities. Its major subsidiaries include Luminant and TXU Energy.

TCEH Finance Refers to TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities.

TCEH Senior Notes Refers collectively to TCEH’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015 Series B (collectively, TCEH 10.25% Notes) and TCEH’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes).

TCEH Senior Secured Facilities Refers collectively to the TCEH Initial Term Loan Facility, TCEH Delayed Draw Term Loan Facility, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 6 to Financial Statements for details of these facilities.

TCEH Senior Secured Second Lien Notes Refers collectively to TCEH’s 15% Senior Secured Second Lien Notes due April 1, 2021 and TCEH’s 15% Senior Secured Second Lien Notes due April 1, 2021, Series B.

TCEQ Texas Commission on Environmental Quality

Texas Holdings Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.

Texas Holdings Group Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities.

Texas Transmission Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of its subsidiaries or any member of the Sponsor Group.

TRE Refers to Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and ERCOT protocols.

TXU Energy Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT.

TXU Gas TXU Gas Company, a former subsidiary of EFH Corp.

US United States of America

VIE variable interest entity

F-97

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Unaudited)

(millions of dollars)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Operating revenues	$	2,607		$	2,885		$	6,599		$	7,366
Fuel, purchased power costs and delivery fees		(1,400	)		(870	)		(3,521	)		(2,171	)
Net gain from commodity hedging and trading activities		992			123			2,272			1,003
Operating costs		(197	)		(388	)		(623	)		(1,171	)
Depreciation and amortization		(352	)		(456	)		(1,043	)		(1,286	)
Selling, general and administrative expenses		(187	)		(277	)		(560	)		(792	)
Franchise and revenue-based taxes		(24	)		(94	)		(73	)		(259	)
Impairment of goodwill (Note 4)		(4,100	)		—			(4,100	)		(90	)
Other income (Note 16)		1,033			45			1,278			71
Other deductions (Note 16)		(4	)		(32	)		(23	)		(50	)
Interest income		—			18			9			30
Interest expense and related charges (Note 16)		(1,018	)		(1,039	)		(3,092	)		(2,136	)
Income (loss) before income taxes and equity in earnings of unconsolidated subsidiaries		(2,650	)		(85	)		(2,877	)		515
Income tax (expense) benefit		(370	)		31			(336	)		(254	)
Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 2)		118			—			240			—
Net income (loss)		(2,902	)		(54	)		(2,973	)		261
Net income attributable to noncontrolling interests		—			(26	)		—			(54	)
Net income (loss) attributable to EFH Corp.	$	(2,902	)	$	(80	)	$	(2,973	)	$	207

See Notes to Financial Statements.

F-98

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(millions of dollars)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Net income (loss)	$	(2,902	)	$	(54	)	$	(2,973	)	$	261
Other comprehensive income (loss), net of tax effects:
Reclassification of pension and other retirement benefit costs (net of tax expense of $8, $—, $8 and $—)		15			—			15			—
Cash flow hedges:
Net decrease in fair value of derivatives (net of tax benefit of $—, $2, $— and $11)		—			(4	)		—			(20	)
Derivative value net loss related to hedged transactions recognized during the period and reported in net income (loss) (net of tax benefit of $7, $21, $25 and $53)		13			41			49			99
Total effect of cash flow hedges		13			37			49			79
Total adjustments to net income (loss)		28			37			64			79
Comprehensive income (loss) operations		(2,874	)		(17	)		(2,909	)		340
Comprehensive income attributable to noncontrolling interests		—			(26	)		—			(54	)
Comprehensive income (loss) attributable to EFH Corp.	$	(2,874	)	$	(43	)	$	(2,909	)	$	286

See Notes to Financial Statements.

F-99

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(millions of dollars)

	Nine Months Ended September 30,
	2010			2009
Cash flows — operating activities:
Net income (loss)	$	(2,973	)	$	261
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		1,321			1,598
Deferred income tax expense — net		562			152
Impairment of goodwill (Note 4)		4,100			90
Write off of regulatory assets (Note 16)		—			25
Increase of toggle notes in lieu of cash interest (Note 6)		269			248
Unrealized net gains from mark-to-market valuations of commodity positions		(1,615	)		(713	)
Unrealized net (gains) losses from mark-to-market valuations of interest rate swaps		542			(527	)
Losses on dedesignated cash flow hedges (interest rate swaps)		73			140
Equity in earnings of unconsolidated subsidiaries		(240	)		—
Distributions of earnings from unconsolidated subsidiaries		141			—
Net gain on debt exchanges (Note 6)		(1,166	)		—
Bad debt expense (Note 5)		88			84
Stock-based incentive compensation expense		13			12
Reversal of use tax accrual (Note 16)		—			(23	)
Net gain on sale of assets		(81	)		(1	)
Other, net		2			(3	)
Changes in operating assets and liabilities:
Impact of accounts receivable securitization program (Note 5)		(383	)		284
Margin deposits — net		164			260
Deferred advanced metering system revenues		—			51
Other operating assets and liabilities		149			(195	)
Cash provided by operating activities		966			1,743
Cash flows — financing activities:
Issuances of long-term debt (Note 6)		500			522
Repayments and repurchases of long-term debt (Note 6)		(1,002	)		(297	)
Net short-term borrowings under accounts receivable securitization program (Note 5)		228			—
Increase (decrease) in other short-term borrowings (Note 6)		(873	)		200
Decrease in note payable to unconsolidated subsidiary		(27	)		—
Contributions from noncontrolling interests		24			42
Distributions paid to noncontrolling interests		—			(32	)
Debt exchange and issuance costs		(46	)		(36	)
Other, net		29			21
Cash provided by (used in) financing activities		(1,167	)		420
Cash flows — investing activities:
Capital expenditures		(709	)		(1,877	)
Nuclear fuel purchases		(84	)		(157	)
Money market fund redemptions		—			142
Investment redeemed/(posted) with derivative counterparty (Note 11)		400			(400	)
Proceeds from sale of assets		141			41
Reduction of letter of credit facility deposited with trustee (Note 6)		—			115
Other changes in restricted cash		(31	)		3
Proceeds from sales of environmental allowances and credits		7			22
Purchases of environmental allowances and credits		(13	)		(23	)
Proceeds from sales of nuclear decommissioning trust fund securities		937			2,972
Investments in nuclear decommissioning trust fund securities		(949	)		(2,983	)
Other, net		(6	)		18
Cash used in investing activities		(307	)		(2,127	)

F-100

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.)

(Unaudited)

(millions of dollars)

	Nine Months Ended September 30,
	2010			2009
Net change in cash and cash equivalents		(508	)		36
Effects of deconsolidation of Oncor Holdings		(29	)		—
Cash and cash equivalents — beginning balance		1,189			1,689
Cash and cash equivalents — ending balance	$	652		$	1,725

See Notes to Financial Statements.

F-101

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(millions of dollars)

	September 30, 2010			December 31, 2009 (see Note 2)
ASSETS
Current assets:
Cash and cash equivalents	$	652		$	1,189
Investment posted with counterparty (Note 11)		—			425
Restricted cash (Note 16)		31			48
Trade accounts receivable — net (2010 includes $885 in pledged amounts related to VIE (Notes 3 and 5))		1,256			1,260
Inventories		388			485
Commodity and other derivative contractual assets (Note 11)		3,520			2,391
Accumulated deferred income taxes		60			5
Margin deposits related to commodity positions		196			187
Other current assets		66			136
Total current assets		6,169			6,126
Restricted cash (Note 16)		1,135			1,149
Receivables from unconsolidated subsidiary (Note 14)		1,270			—
Investments in unconsolidated subsidiaries (Note 2)		5,525			44
Other investments (Note 16)		667			706
Property, plant and equipment — net (Note 16)		20,530			30,108
Goodwill (Note 4)		6,152			14,316
Identifiable intangible assets — net (Note 4)		2,466			2,876
Regulatory assets — net		—			1,959
Commodity and other derivative contractual assets (Note 11)		2,553			1,533
Other noncurrent assets, principally unamortized debt issuance costs		647			845
Total assets	$	47,114		$	59,662
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (2010 includes $228 related to a VIE (Notes 3 and 6))	$	308		$	1,569
Long-term debt due currently (Note 6)		252			417
Trade accounts payable		647			896
Payables due to unconsolidated subsidiary (Note 14)		279			—
Commodity and other derivative contractual liabilities (Note 11)		3,065			2,392
Margin deposits related to commodity positions		693			520
Accrued interest		651			526
Other current liabilities		380			744
Total current liabilities		6,275			7,064
Accumulated deferred income taxes		5,317			6,131
Investment tax credits		—			37
Commodity and other derivative contractual liabilities (Note 11)		1,422			1,060
Notes or other liabilities due to unconsolidated subsidiary (Note 14)		372			—
Long-term debt, less amounts due currently (Note 6)		35,169			41,440
Other noncurrent liabilities and deferred credits (Note 16)		4,627			5,766
Total liabilities		53,182			61,498
Commitments and Contingencies (Note 7)
Equity (Note 8):
EFH Corp. shareholders’ equity		(6,139	)		(3,247	)
Noncontrolling interests in subsidiaries		71			1,411
Total equity		(6,068	)		(1,836	)
Total liabilities and equity	$	47,114		$	59,662

See Notes to Financial Statements.

F-102

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 with operations consisting principally of our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority (approximately 80%) owned subsidiary engaged in regulated electricity transmission and distribution operations in Texas. See Note 3 regarding the deconsolidation of Oncor (and its majority owner, Oncor Holdings) as a result of amended consolidation accounting standards related to variable interest entities (VIEs) effective January 1, 2010.

References in these financial statements to “we,” “our,” “us” and “the company” are to EFH Corp. and/or its subsidiaries, TCEH and/or its subsidiaries, or Oncor and/or its subsidiary as apparent in the context. See “Glossary” for other defined terms.

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

We have two reportable segments: the Competitive Electric segment, which is comprised principally of TCEH, and the Regulated Delivery segment, which is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary. See Note 15 for further information concerning reportable business segments.

Basis of Presentation

The condensed consolidated financial statements have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in the 2009 Form 10-K with the exception of the prospective adoption of amended guidance regarding consolidation accounting standards related to VIEs that resulted in the deconsolidation of Oncor Holdings as discussed in Note 3 and amended guidance regarding transfers of financial assets that resulted in the accounts receivable securitization program no longer being accounted for as a sale of accounts receivable and the funding under the program now reported as short-term borrowings as discussed in Note 5. Investments in unconsolidated subsidiaries, which are 50% or less owned and/or do not meet accounting standards criteria for consolidation, are accounted for under the equity method (see Notes 2 and 3). All 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. All acquisitions of outstanding debt for cash, including the notes that had been issued in lieu of cash interest, are presented in the financing activities section of the statement of cash flows. 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 2009 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-103

Use of Estimates

Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities as of the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates or assumptions during the current year.

Changes in Accounting Standards

As of January 1, 2010, we adopted new FASB guidance that requires reconsideration of consolidation conclusions for all VIEs and other entities with which we are involved. See Note 3 for discussion of our evaluation of VIEs and the resulting deconsolidation of Oncor Holdings and its subsidiaries that resulted in our investment in Oncor Holdings and its subsidiaries being prospectively reported as an equity method investment. There were no other material effects on our financial statements as a result of the adoption of this new guidance.

As of January 1, 2010, we adopted new FASB guidance regarding accounting for transfers of financial assets that eliminates the concept of a qualifying special purpose entity, changes the requirements for derecognizing financial assets and requires additional disclosures. Accordingly, the trade accounts receivable amounts under the accounts receivable securitization program discussed in Note 5 are prospectively reported as pledged balances, and the related funding amounts are reported as short-term borrowings. Prior to January 1, 2010, the activity was accounted for as a sale of accounts receivable in accordance with previous accounting standards, which resulted in the funding being recorded as a reduction of accounts receivable. This new guidance does not impact the covenant-related ratio calculations in our debt agreements.

F-104

2. EQUITY METHOD INVESTMENTS

Investments in unconsolidated subsidiaries consisted of the following:

	September 30, 2010		December 31, 2009
Investment in Oncor Holdings (100% owned) (a)	$	5,525	$	—
Investment in natural gas gathering pipeline business (b)		—		44
Total investments in unconsolidated subsidiaries	$	5,525	$	44

(a) Oncor Holdings was deconsolidated effective January 1, 2010 (see Notes 1 and 3).

(b) A controlling interest in this previously consolidated subsidiary was sold in 2009, and the remaining interests were sold in June 2010.

Oncor Holdings

Effective January 1, 2010, we account for our investment in Oncor Holdings under the equity method (see Note 3). Prior to this date, Oncor Holdings was a consolidated subsidiary. Oncor Holdings owns approximately 80% of Oncor (an SEC registrant), which is engaged in regulated electricity transmission and distribution operations in Texas. Distribution revenues from TCEH represented 38% of total revenues for Oncor Holdings for both the nine months ended September 30, 2010 and 2009. Condensed statements of consolidated income of Oncor Holdings for the three and nine months ended September 30, 2010 and 2009 are presented below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Operating revenues	$	831		$	770		$	2,236		$	2,037
Operation and maintenance expenses		(256	)		(245	)		(757	)		(698	)
Depreciation and amortization		(176	)		(147	)		(507	)		(405	)
Taxes other than income taxes		(100	)		(99	)		(287	)		(287	)
Other income		8			10			28			30
Other deductions		(1	)		(30	)		(5	)		(39	)
Interest income		9			13			29			32
Interest expense and related charges		(87	)		(85	)		(259	)		(258	)
Income before income taxes		228			187			478			412
Income tax expense		(80	)		(56	)		(177	)		(141	)
Net income		148			131			301			271
Net income attributable to noncontrolling interests		(30	)		(26	)		(61	)		(54	)
Net income attributable to Oncor Holdings	$	118		$	105		$	240		$	217

F-105

Assets and liabilities of Oncor Holdings as of September 30, 2010 and December 31, 2009 are presented below:

	September 30, 2010		December 31, 2009
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	11	$	29
Restricted cash		63		47
Trade accounts receivable — net		291		243
Trade accounts and other receivables from affiliates		220		188
Income taxes receivable from EFH Corp.		59		—
Inventories		94		92
Accumulated deferred income taxes		1		10
Prepayments		75		76
Other current assets		4		8
Total current assets		818		693
Restricted cash		16		14
Other investments		76		72
Property, plant and equipment — net		9,529		9,174
Goodwill		4,064		4,064
Note receivable due from TCEH		189		217
Regulatory assets — net		1,652		1,959
Other noncurrent assets		238		51
Total assets	$	16,582	$	16,244
LIABILITIES
Current liabilities:
Short-term borrowings	$	428	$	616
Long-term debt due currently		111		108
Trade accounts payable — nonaffiliates		111		129
Income taxes payable to EFH Corp.		—		5
Accrued taxes other than income		116		137
Accrued interest		73		104
Other current liabilities		94		106
Total current liabilities		933		1,205
Accumulated deferred income taxes		1,478		1,369
Investment tax credits		34		37
Long-term debt, less amounts due currently		5,395		4,996
Other noncurrent liabilities and deferred credits		1,775		1,879
Total liabilities	$	9,615	$	9,486

F-106

Oncor Debt Issue and Exchange

In September 2010, Oncor issued $475 million aggregate principal amount of 5.250% senior secured notes maturing in September 2040. Oncor used the net proceeds of approximately $465 million from the sale of the notes to repay borrowings under its revolving credit facility, including loans under the revolving credit facility made by certain of the initial purchasers or their affiliates, and for general corporate purposes. The notes are secured by a first priority lien equally and ratably with all of Oncor’s other secured indebtedness.

In October 2010, Oncor issued approximately $324.4 million aggregate principal amount of 5.000% senior secured notes due 2017 and approximately $126.3 million aggregate principal amount of 5.750% senior secured notes due 2020 in exchange for an equivalent principal amount of its outstanding 6.375% senior secured notes due 2012 and 5.950% senior secured notes due 2013, respectively, that were validly tendered. Oncor did not receive any cash proceeds from the exchange.

F-107

3. CONSOLIDATION OF VARIABLE INTEREST ENTITIES

We adopted amended accounting standards on January 1, 2010 that require consolidation of a VIE if we have the power to direct the significant activities of the VIE and the right or obligation to absorb profit and loss from the VIE. A VIE is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. As discussed below, our balance sheet includes assets and liabilities of VIEs that meet the consolidation standards and also reflects the deconsolidation of Oncor Holdings, which holds an approximate 80% interest in Oncor.

Our variable interests consist of equity investments. In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationships among the interest holders of the VIE and the nature of any special rights granted to the interest holders of the VIE.

Consolidated VIEs

See discussion in Note 5 regarding the VIE related to our accounts receivable securitization program that continues to be consolidated under the amended accounting standards.

We also continue to consolidate Comanche Peak Nuclear Power Company LLC (CPNPC), which was formed by subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at our existing Comanche Peak nuclear-fueled generation facility using MHI’s US-Advanced Pressurized Water Reactor technology and to obtain a combined operating license from the NRC. CPNPC is currently financed through capital contributions from the subsidiaries of TCEH and MHI that hold 88% and 12% of CPNPC’s equity interests, respectively (see Note 8).

The carrying amounts and classifications of the assets and liabilities related to our consolidated VIEs as of September 30, 2010 are as follows:

Assets:			Liabilities:
Cash and cash equivalents	$	9	Short-term borrowings (a)	$	228
Accounts receivable (a)		885	Trade accounts payable		4
Property, plant and equipment		105	Other current liabilities		1
Other assets, including $2 of current assets		8
Total assets	$	1,007	Total liabilities	$	233

(a) As a result of the January 1, 2010 adoption of new accounting guidance related to transfers of financial assets, the balance sheet as of September 30, 2010 reflects $885 million of pledged accounts receivable and $228 million of short-term borrowings (see Note 5).

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

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Non-Consolidated VIEs

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

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

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

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

We account for our investment in Oncor Holdings under the equity method, as opposed to the cost method, because we have the ability to exercise significant influence (as defined by US GAAP) over its activities. Our maximum exposure to loss from our variable interests in VIEs does not exceed our carrying value. See Note 2 for additional information about equity method investments including condensed income statement and balance sheet data for Oncor Holdings.

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4. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The following table provides the goodwill balances as of September 30, 2010 and the changes in such balances for the nine months ended September 30, 2010. With the deconsolidation of Oncor (including its $4.064 billion goodwill balance) effective January 1, 2010, the amounts below relate only to our competitive business. None of the goodwill is being deducted for tax purposes.

As of January 1, 2010:
Goodwill before impairment charges	$	18,342
Accumulated impairment charges (a)		(8,090	)
Balance as of January 1, 2010		10,252
Changes – nine months ended September 30, 2010:
Impairment charge		(4,100	)
As of September 30, 2010:
Goodwill before impairment charges		18,342
Accumulated impairment charges		(12,190	)
Balance as of September 30, 2010	$	6,152

(a) Includes $20 million recorded in Corporate and Other results.

Goodwill Impairment

In the third quarter 2010, we recorded a $4.1 billion noncash goodwill impairment charge related to the Competitive Electric segment. The impairment charge reflected the estimated effect of lower wholesale power prices on the enterprise value of the Competitive Electric segment, driven by the sustained decline in forward natural gas prices, as indicated by our cash flow projections and declines in market values of securities of comparable companies.

The calculation of the goodwill impairment involved the following steps: first, we estimated the debt-free enterprise value of our competitive business taking into account future estimated cash flows and current securities values of comparable companies; second, we estimated the fair values of the individual operating assets and liabilities of our competitive business; third, we calculated “implied” goodwill as the excess of the estimated enterprise value over the estimated value of the net operating assets; and finally, we compared the implied goodwill amount to the carrying value of goodwill and recorded an impairment charge for the amount the carrying value of goodwill exceeded implied goodwill.

The impairment determination involved significant assumptions and judgments. The calculations supporting the estimates of the enterprise value of our competitive business and the fair values of certain of its operating assets and liabilities utilized models that take into consideration multiple inputs, including commodity prices, discount rates, debt yields, securities prices of comparable companies and other inputs, assumptions regarding each of which could have a significant effect on valuations. The fair value measurements resulting from these models are classified as non-recurring Level 3 measurements consistent with accounting standards related to the determination of fair value (see Note 9).

The goodwill impairment testing in the third quarter 2010 resulted from current market conditions, and the annual impairment testing required by accounting rules remains scheduled for December 1, 2010. We cannot predict the likelihood or amount of any future impairment.

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Identifiable Intangible Assets

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

	As of September 30, 2010 (a)						As of December 31, 2009
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	274	$	189	$	463	$	215	$	248
Favorable purchase and sales contracts		548		247		301		700		374		326
Capitalized in-service software		271		88		183		490		167		323
Environmental allowances and credits		994		282		712		992		212		780
Land easements		—		—		—		188		72		116
Mining development costs		47		14		33		32		5		27
Total intangible assets subject to amortization	$	2,323	$	905		1,418	$	2,865	$	1,045		1,820
Trade name (not subject to amortization)						955						955
Mineral interests (not currently subject to amortization)						93						101
Total intangible assets					$	2,466					$	2,876

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

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

			Three Months  Ended September 30,				Nine Months  Ended September 30,
Identifiable Intangible Asset	Income Statement Line	Segment	2010		2009		2010		2009
Retail customer relationship	Depreciation and amortization	Competitive Electric	$	20	$	21	$	59	$	64
Favorable purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees	Competitive Electric		1		18		25		91
Capitalized in-service software	Depreciation and amortization	All (a)		9		16		26		39
Environmental allowances and credits	Fuel, purchased power costs and delivery fees	Competitive Electric		25		25		69		66
Land easements	Depreciation and amortization	Regulated Delivery (a)		—		1		—		2
Mining development costs	Depreciation and amortization	Competitive Electric		3		1		8		2
Total amortization expense			$	58	$	82	$	187	$	264

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

Estimated Amortization of Intangible Assets — The estimated aggregate amortization expense of intangible assets for each of the next five fiscal years is as follows:

Year	Amount
2010	$	252
2011		192
2012		151
2013		129
2014		114

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5. TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM

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

In June 2010, the accounts receivable securitization program was amended. The amendments, among other things, reduced the maximum funding amount under the program to $350 million from $700 million. Program funding declined from $383 million as of December 31, 2009 to $228 million as of September 30, 2010. Under the terms of the program, available funding was reduced by $42 million of customer deposits held by the originator because TCEH’s credit ratings were lower than Ba3/BB-. The declines in actual and maximum funding amounts reflected exclusion of receivables under contractual sales agreements.

All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Ongoing changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, reflect seasonal variations in the level of accounts receivable, changes in collection trends and other factors such as changes in sales prices and volumes. TXU Receivables Company has issued a subordinated note payable to the originator for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originator that was funded by the sale of the undivided interests. The subordinated note issued by TXU Receivables Company is subordinated to the undivided interests of the funding entities in the purchased receivables. The balance of the subordinated note payable, which is eliminated in consolidation, totaled $657 million and $463 million as of September 30, 2010 and December 31, 2009, respectively.

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

Program fee amounts were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Program fees	$	2		$	2		$	7		$	9
Program fees as a percentage of average funding (annualized)		4.8	%		1.3	%		3.3	%		2.4	%

Funding under the program decreased $155 million for the nine months ended September 30, 2010 and increased $284 million for the nine months ended September 30, 2009.

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Activities of TXU Receivables Company were as follows:

	Nine Months Ended September 30,
	2010			2009
Cash collections on accounts receivable	$	4,828		$	4,660
Face amount of new receivables purchased		(4,867	)		(5,165	)
Discount from face amount of purchased receivables		9			11
Program fees paid to funding entities		(7	)		(9	)
Servicing fees paid to Service Co. for recordkeeping and collection services		(2	)		(2	)
Increase in subordinated notes payable		194			221
Financing/operating cash flows used by (provided to) originator under the program	$	155		$	(284	)

Changes in funding under the program have previously been reported as operating cash flows, and the amended accounting rule requires that the amount of funding under the program upon the January 1, 2010 adoption ($383 million) be reported as a use of operating cash flows and a source of financing cash flows. All changes in funding subsequent to adoption of the amended standard are reported as financing activities.

The program, which expires in October 2013, may be terminated upon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds, and the funding entities do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Receivables Company or Service Co. defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities, or if TCEH, any affiliate of TCEH acting as collection agent other than Service Co., any parent guarantor of the originator or the originator shall default in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. As of September 30, 2010, there were no such events of termination.

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

Trade Accounts Receivable

	September 30, 2010 (a)			December 31, 2009
Wholesale and retail trade accounts receivable, including $885 in pledged retail receivables as of September 30, 2010	$	1,328		$	1,726
Undivided interests in retail accounts receivable sold by TXU Receivables Company		—			(383	)
Allowance for uncollectible accounts		(72	)		(83	)
Trade accounts receivable — reported in balance sheet	$	1,256		$	1,260

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

Gross trade accounts receivable as of September 30, 2010 and December 31, 2009 included unbilled revenues totaling $351 million and $546 million, respectively.

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Allowance for Uncollectible Accounts Receivable

	Nine Months Ended September 30,
	2010			2009
Allowance for uncollectible accounts receivable as of beginning of period	$	81		$	70
Increase for bad debt expense		88			84
Decrease for account write-offs		(97	)		(67	)
Other		—			(1	)
Allowance for uncollectible accounts receivable as of end of period	$	72		$	86

6. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

As of September 30, 2010, outstanding short-term borrowings totaled $308 million, which included $80 million under TCEH credit facilities at a weighted average interest rate of 3.84%, excluding certain customary fees, and $228 million under the accounts receivable securitization program discussed in Note 5.

As of December 31, 2009, we had outstanding short-term borrowings of $1.569 billion at a weighted average interest rate of 2.50%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $953 million for TCEH and $616 million for Oncor.

Credit Facilities

Credit facilities with cash borrowing and/or letter of credit availability as of September 30, 2010 are presented below. The facilities are all senior secured facilities of TCEH.

		As of September 30, 2010
Authorized Borrowers and Facility	Maturity Date	Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Revolving Credit Facility (a)	October 2013	$	2,700	$	—	$	80	$	2,620
TCEH Letter of Credit Facility (b)	October 2014		1,250		—		1,250		—
Subtotal TCEH		$	3,950	$	—	$	1,330	$	2,620
TCEH Commodity Collateral Posting Facility (c)	December 2012		Unlimited	$	—	$	—		Unlimited

(a) Facility used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount includes $229 million of commitments from Lehman that are only available from the fronting banks and the swingline lender. All outstanding borrowings under this facility as of September 30, 2010 bear interest at LIBOR plus 3.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion of the facility.

(b) Facility used for issuing letters of credit for general corporate purposes, including, but not limited to, providing collateral support under hedging arrangements and other commodity transactions that are not eligible for funding under the TCEH Commodity Collateral Posting Facility. The borrowings under this facility were drawn at the inception of the facility, are classified as long-term debt, and except for $115 million related to a letter of credit drawn in June 2009, have been retained as restricted cash. Letters of credit totaling $725 million issued as of September 30, 2010 are supported by the restricted cash, and the remaining letter of credit availability totals $410 million.

(c) Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 435 million MMBtu as of September 30, 2010. As of September 30, 2010, there were no borrowings under this facility. See “TCEH Senior Secured Facilities” below for additional information.

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Long-Term Debt

As of September 30, 2010 and December 31, 2009, long-term debt consisted of the following:

	September 30, 2010			December 31, 2009
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			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			171
0.277% Floating Series 2001D-2 due May 1, 2033 (b)		97			97
0.297% Floating Taxable Series 2001I due December 1, 2036 (c)		62			62
0.286% 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
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)		(136	)		(147	)
Senior Secured Facilities:
3.828% TCEH Initial Term Loan Facility maturing October 10, 2014 (e)(f)(g)		15,936			16,079
3.758% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (e)(f)		4,044			4,075
3.756% TCEH Letter of Credit Facility maturing October 10, 2014 (f)		1,250			1,250
0.250% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (h)		—			—
Other:
10.25% Fixed Senior Notes due November 1, 2015 (i)		2,813			2,944
10.25% Fixed Senior Notes due November 1, 2015, Series B (i)		1,850			1,913
10.50 / 11.25% Senior Toggle Notes due November 1, 2016 (j)		1,992			1,952
7.000% Fixed Senior Notes due March 15, 2013		5			5
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		42			55
Capital lease obligations		80			153
Unamortized fair value discount (d)		(3	)		(4	)
Total TCEH	$	29,408		$	29,810

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	September 30, 2010			December 31, 2009
EFCH
9.580% Fixed Notes due in semiannual installments through December 4, 2019	$	51		$	51
8.254% Fixed Notes due in quarterly installments through December 31, 2021		47			50
1.266% 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)		(10	)		(11	)
Total EFCH		97			99
EFH Corp. (parent entity)
10.875% Fixed Senior Notes due November 1, 2017 (k)		359			1,831
11.25 / 12.00% Senior Toggle Notes due November 1, 2017 (k)		539			2,797
9.75% Fixed Senior Secured Notes due October 15, 2019		115			115
10.000% Fixed Senior Secured Notes due January 15, 2020		1,061			—
5.550% Fixed Senior Notes Series P due November 15, 2014 (l)		434			983
6.500% Fixed Senior Notes Series Q due November 15, 2024 (l)		740			740
6.550% Fixed Senior Notes Series R due November 15, 2034 (l)		744			744
8.820% Building Financing due semiannually through February 11, 2022 (m)		68			75
Unamortized fair value premium related to Building Financing (d)		15			17
Capital lease obligations		5			—
Unamortized fair value discount (d)		(485	)		(599	)
Total EFH Corp.		3,595			6,703
EFIH
9.75% Fixed Senior Secured Notes due October 15, 2019		141			141
10.000% Fixed Senior Secured Notes due December 1, 2020		2,180			—
Total EFIH		2,321			141
Oncor (n) (o)
6.375% Fixed Senior Notes due May 1, 2012		—			700
5.950% Fixed Senior Notes due September 1, 2013		—			650
6.375% Fixed Senior Notes due January 15, 2015		—			500
6.800% Fixed Senior Notes due September 1, 2018		—			550
7.000% Fixed Debentures due September 1, 2022		—			800
7.000% Fixed Senior Notes due May 1, 2032		—			500
7.250% Fixed Senior Notes due January 15, 2033		—			350
7.500% Fixed Senior Notes due September 1, 2038		—			300
Unamortized discount		—			(15	)
Total Oncor		—			4,335
Oncor Electric Delivery Transition Bond Company LLC (o) (p)
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		—			13
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		—			130
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		—			145
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		—			197
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		—			290
Total Oncor Electric Delivery Transition Bond Company LLC		—			775
Unamortized fair value discount related to transition bonds (d)		—			(6	)
Total Oncor consolidated		—			5,104
Total EFH Corp. consolidated		35,421			41,857
Less amount due currently		(252	)		(417	)
Total long-term debt	$	35,169		$	41,440

(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 as of September 30, 2010. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(c) Interest rate in effect as of September 30, 2010. This series is in a weekly interest rate mode and is classified as long-term as it is supported by long-term irrevocable letters of credit.

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

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(e) Interest rate swapped to fixed on $16.30 billion principal amount.

(f) Interest rates in effect as of September 30, 2010.

(g) Amount excludes $20 million that is held by EFH Corp. and eliminated in consolidation.

(h) Interest rate in effect as of September 30, 2010, excluding a quarterly maintenance fee of $11 million. See “Credit Facilities” above for more information.

(i) Amounts exclude $187 million and $150 million of the TCEH Senior Notes and TCEH Senior Notes, Series B, respectively, that are held either by EFH Corp. or EFIH and eliminated in consolidation.

(j) Amount excludes $70 million that is held by EFH Corp. and eliminated in consolidation.

(k) Amounts exclude $1.428 billion and $2.166 billion of 10.875% Notes and Toggle Notes, respectively, that are held by EFIH and eliminated in consolidation.

(l) Amounts exclude $9 million, $6 million and $3 million of the Series P, Series Q and Series R notes, respectively, that are held by EFIH and eliminated in consolidation.

(m) This financing is secured and will be serviced with cash drawn by the beneficiary of a letter of credit.

(n) Secured with first priority lien.

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

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

Debt-Related Activity in 2010 — Repayments of long-term debt in 2010 totaling $247 million included $154 million of principal payments at scheduled maturity dates as well as other repayments totaling $93 million principally related to capitalized leases. See “2010 Debt Exchanges, Repurchases and Issuances” below for discussion of $4.722 billion principal amount of debt acquired in debt exchanges and repurchases completed in the nine months ended September 30, 2010 and $913 million principal amount of debt acquired in debt exchanges and repurchases in October 2010.

During the second quarter, EFH Corp. issued, through the payment-in-kind (PIK) election, $162 million principal amount of its 11.25%/12.00% Senior Toggle Notes due November 2017 (EFH Corp. Toggle Notes) and TCEH issuing, through the PIK election, $110 million principal amount of its 10.50%/11.25% Senior Toggle Notes due November 2016 (TCEH Toggle Notes), in each case, in lieu of making cash interest payments.

2010 Debt Exchanges, Repurchases and Issuances — Debt exchanges and repurchases completed year-to-date October 28, 2010 resulted in acquisitions of $5.635 billion aggregate principal amount of outstanding EFH Corp. and TCEH debt with due dates largely 2017 or earlier in exchange for $3.077 billion aggregate principal amount of new debt and $1.042 billion in cash. The new debt issued in exchange transactions consisted of $2.180 billion aggregate principal amount of EFIH 10% Notes due 2020, $561 million aggregate principal amount of EFH Corp. 10% Notes due 2020 and $336 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021. EFH Corp. also issued $500 million principal amount of EFH Corp. 10% Notes due 2020 for cash, and TCEH issued $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) due 2021 for cash. A discussion of these transactions, which were private, except as noted, and descriptions of the EFIH 10% Notes, EFH Corp. 10% Notes and TCEH 15% Senior Secured Second Lien Notes are presented below.

Transactions completed in October 2010 were as follows:

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

• TCEH and TCEH Finance issued $350 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) due 2021, and used $290 million of the proceeds to acquire TCEH Senior Notes as described immediately below. The remaining net proceeds totaling $53 million are being held in escrow pending their use for the payment, repayment or prepayment of term loans under the TCEH Senior Secured Facilities and/or the repurchase of outstanding principal amounts of TCEH Senior Notes. If proceeds remain in the escrow account on March 31, 2013, the issuers will be required to use such amounts to offer to repurchase TCEH 15% Senior Secured Second Lien Notes (Series B) due 2021 at a price of 100% of the principal amount thereof, plus accrued interest.

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• TCEH repurchased $226 million principal amount of TCEH 10.25% Notes and $200 million principal amount of TCEH Toggle Notes for $290 million in cash using the proceeds from the issuance described immediately above and paid accrued interest from cash on hand.

• EFH Corp. repurchased $9 million principal amount of TCEH Toggle Notes for $5 million in cash.

Transactions completed in the three months ended September 30, 2010 were as follows:

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

• EFH Corp. issued $455 million principal amount of EFH Corp. 10% Notes due 2020 in exchange for $549 million principal amount of EFH Corp. 5.55% Series P Senior Notes (EFH Corp. 5.55% Notes), $25 million principal amount of EFH Corp. Toggle Notes, $25 million principal amount of EFH Corp. 10.875% Notes and $13 million principal amount of TCEH 10.25% Notes.

• EFH Corp. repurchased $28 million principal amount of EFH Corp. Toggle Notes, $13 million principal amount of TCEH 10.25% Notes and $15 million principal amount of TCEH Toggle Notes for $36 million in cash plus accrued interest.

These transactions resulted in debt extinguishment gains totaling $1.023 billion (reported as other income).

In connection with the registered debt exchange transaction, EFH Corp. received the requisite consents from holders of the EFH Corp. Senior Notes and executed a supplemental indenture to incorporate certain amendments to the indenture that governs the EFH Corp. Senior Notes. These amendments, among other things, eliminate substantially all of the restrictive covenants related to the EFH Corp. Senior Notes, eliminate certain events of default, modify covenants regarding mergers and consolidations, and modify or eliminate certain other provisions.

Transactions completed in the three months ended June 30, 2010 were as follows:

• EFH Corp. repurchased $96 million principal amount of EFH Corp. Toggle Notes, $19 million principal amount of EFH Corp. 10.875% Notes, $168 million principal amount of TCEH 10.25% Notes, $8 million principal amount of TCEH Toggle Notes and $20 million principal amount of TCEH’s initial term loans under its Senior Secured Facilities for $211 million in cash plus accrued interest.

• EFH Corp. issued $72 million principal amount of EFH Corp. 10% Notes due 2020 in exchange for $85 million principal amount of EFH Corp. Toggle Notes and $17 million principal amount of TCEH Toggle Notes.

• These transactions resulted in debt extinguishment gains totaling $129 million (reported as other income).

Transactions completed in the three months ended March 31, 2010 were as follows:

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

• EFH Corp. issued $34 million principal amount of EFH Corp. 10% Notes due 2020 in exchange for $20 million principal amount of EFH Corp. Toggle Notes and $27 million principal amount of TCEH Toggle Notes resulting in a debt extinguishment gain of $14 million (reported as other income).

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The EFH Corp. notes acquired by EFIH and the TCEH notes and initial term loans under the TCEH Senior Secured Facilities acquired by EFH Corp. are held as an investment, and are eliminated in consolidation. All other securities acquired in the above transactions have been cancelled.

EFIH 10% Notes — The EFIH 10% Notes mature in December 2020, with interest payable in cash semi-annually in arrears on June 1 and December 1, beginning December 1, 2010, at a fixed rate of 10% per annum. The EFIH 10% Notes are secured by EFIH’s pledge of 100% of the membership interests and other investments it owns in Oncor Holdings (such membership interests and other investments, the Collateral). The EFIH 10% Notes are secured on an equal and ratable basis with the EFIH 9.75% Notes and EFIH’s guarantee of the EFH Corp. Senior Secured Notes.

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

The EFIH 10% Notes and the indenture governing such notes restrict the Issuers’ and their respective restricted subsidiaries’ ability to, among other things, make restricted payments, incur debt and issue preferred stock, incur liens, pay dividends, merge, consolidate or sell assets and engage in transactions with affiliates. These covenants are subject to a number of important limitations and exceptions. The notes and the related indenture also contain customary events of default, including, among others, failure to pay principal or interest on the notes when due. If certain events of default occur and are continuing under the notes and the related indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes may declare the principal amount of the notes to be due and payable immediately. Currently, there are no restricted subsidiaries under the notes and the related indenture (other than EFIH Finance, which has no assets). Oncor Holdings, Oncor and their respective subsidiaries are unrestricted subsidiaries under the EFIH 10% Notes and the related indenture and, accordingly, are not subject to any of the restrictive covenants in the notes and the related indenture.

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

EFH Corp. 10% Notes — The EFH Corp. 10% Notes mature in January 2020, with interest payable in cash semi-annually in arrears on January 15 and July 15, beginning July 15, 2010, at a fixed rate of 10% per annum. The notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and EFIH. The guarantee from EFIH is secured by the pledge of the Collateral. The guarantee from EFCH is not secured. EFIH’s guarantee of the EFH Corp. 10% Notes is secured by the Collateral on an equal and ratable basis with the EFIH Notes and EFIH’s guarantee of the EFH Corp. 9.75% Notes.

The EFH Corp. 10% Notes are a senior obligation and rank equally in right of payment with all senior indebtedness of EFH Corp. and are senior in right of payment to any future subordinated indebtedness of EFH Corp. These notes are effectively subordinated to any indebtedness of EFH Corp. secured by assets of EFH Corp. to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other liabilities of EFH Corp.’s non-guarantor subsidiaries.

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

The EFH Corp. 10% Notes and indenture governing such notes restrict EFH Corp. and its restricted subsidiaries’ ability to, among other things, make restricted payments, incur debt and issue preferred stock, incur liens, pay dividends, merge, consolidate or sell assets and engage in certain transactions with affiliates. These covenants are subject to a number of limitations and exceptions. These notes and related indenture also contain customary events of default, including, among others, failure to pay principal or interest on the notes when due. If certain events of default occur and are continuing under these notes and the related indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes may declare the principal amount of the notes to be due and payable immediately.

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

The EFH Corp. 10% Notes were issued in private placements 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. 10% Notes (except for provisions relating to the transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the EFH Corp. 10% Notes. EFH Corp. has agreed to use commercially reasonable efforts to cause the exchange offer to be completed or, if required under special circumstances, to have one or more shelf registration statements declared effective, within 360 days after the issue date of the notes. If this obligation is not satisfied (a Registration Default), the annual interest rate on the notes will increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter the annual interest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues. If the Registration Default is cured, the interest rate on the notes will revert to the original level.

TCEH 15% Senior Secured Second Lien Notes — The TCEH 15% Senior Secured Second Lien Notes and the TCEH 15% Senior Secured Second Lien Notes (Series B) (collectively, the TCEH Senior Secured Second Lien Notes) mature in April 2021, with interest payable in cash quarterly in arrears on January 1, April 1, July 1 and October 1, beginning January 1, 2011, at a fixed rate of 15% per annum. The notes are unconditionally guaranteed on a joint and several basis by EFCH and subsidiary guarantors (collectively, the Guarantors). The notes are secured, on a second-priority basis, by security interests in all of the assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of the assets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to the extent such assets and security interests secure obligations under the TCEH Senior Secured Credit Facilities on a first-priority basis (the TCEH Collateral), subject to certain exceptions and permitted liens. The guarantee from EFCH is not secured.

The TCEH Senior Secured Second Lien Notes are a senior obligation and rank equally in right of payment with all senior indebtedness of TCEH, are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to TCEH’s obligations under the TCEH Senior Secured Credit Facilities and TCEH’s commodity and interest rate hedges that are secured by a first-priority lien on the TCEH Collateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extent of the value of the TCEH Collateral, and to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.

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The guarantees of the TCEH Senior Secured Second Lien Notes from the Subsidiary Guarantors are effectively senior to any unsecured debt of the Subsidiary Guarantors to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral). These guarantees are effectively subordinated to all debt of the Subsidiary Guarantors secured by the TCEH Collateral on a first-priority basis or that is secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateral securing that debt. EFCH’s guarantee ranks equally with its unsecured debt (including debt it guarantees on an unsecured basis) and is effectively subordinated to any of its secured debt to the extent of the value of the collateral securing that debt.

The TCEH Senior Secured Second Lien Notes and indenture governing such notes restrict TCEH’s and its restricted subsidiaries’ ability to, among other things, make restricted payments, including certain investments, incur debt and issue preferred stock, incur liens, pay dividends, merge, consolidate or sell assets and engage in transactions with affiliates. These covenants are subject to a number of limitations and exceptions. These notes and related indenture also contain customary events of default, including, among others, failure to pay principal or interest on the notes when due. In general, all of the series of TCEH Senior Secured Second Lien Notes vote together as a single class. As a result, if certain events of default occur under the related indenture, the trustee or the holders of at least 30% of aggregate principal amount of all outstanding TCEH Senior Secured Second Lien Notes may declare the principal amount on all such notes to be due and payable immediately.

Until October 1, 2013, TCEH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of each series of the TCEH Senior Secured Second Lien Notes from time to time at a redemption price of 115.00% of the aggregate principal amount of the notes being redeemed, plus accrued interest. TCEH may redeem each series of the notes at any time prior to October 1, 2015 at a price equal to 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture. TCEH may also redeem each series of the notes, in whole or in part, at any time on or after October 1, 2015, at specified redemption prices, plus accrued interest. Upon the occurrence of a change of control (as described in the indenture), TCEH must offer to repurchase each series of the notes at 101% of their principal amount, plus accrued interest.

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

TCEH Senior Secured Facilities — The applicable rate on 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 as of September 30, 2010 is provided in the long-term debt table and in the discussion of short-term borrowings above and reflects LIBOR-based borrowings. These borrowings totaled $21.310 billion as of September 30, 2010, excluding $20 million held by EFH Corp. as a result of debt repurchases.

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

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

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

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

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

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

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

Under the terms of the TCEH Senior Secured Facilities, the commitments of the lenders to make loans to TCEH are several and not joint. Accordingly, if any lender fails to make loans to TCEH, TCEH’s available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the TCEH Senior Secured Facilities.

The TCEH Senior Secured Facilities are unconditionally guaranteed jointly and severally on a senior secured basis by EFCH, and subject to certain exceptions, each existing and future direct or indirect wholly-owned US restricted subsidiary of TCEH. The TCEH Senior Secured Facilities, including the guarantees thereof, certain commodity hedging transactions and the interest rate swaps described under “TCEH Interest Rate Swap Transactions” 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 and (b) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.

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 in October 2014. The TCEH Delayed Draw Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the actual principal outstanding under such facility as of December 2009 ($10 million quarterly), with the balance payable in October 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time until October 2013. The TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility will mature in October 2014 and December 2012, respectively.

TCEH Senior Notes — TCEH’s 10.25% Notes bear interest that is payable semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.25% per annum payable in cash. TCEH’s Toggle Notes bear interest that is payable semiannually 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. For any interest period until November 2012, the issuers may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new TCEH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Once TCEH makes a PIK election, the election is valid for each succeeding interest payment period until TCEH revokes the election.

The TCEH 10.25% and Toggle Notes (collectively, the TCEH Senior Notes) had a total principal amount as of September 30, 2010 of $6.655 billion (excluding $407 million principal amount held by EFH Corp. and EFIH) and are fully and unconditionally guaranteed on a joint and several unsecured basis by TCEH’s direct parent, EFCH (which owns 100% of TCEH and its subsidiary guarantors), and by each subsidiary that guarantees the TCEH Senior Secured Facilities.

The issuers may redeem the TCEH 10.25% Notes and TCEH Toggle Notes at any time prior to November 1, 2011 and 2012, respectively, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. The issuers may redeem the TCEH 10.25% Notes and TCEH Toggle Notes, in whole or in part, at any time on or after November 1, 2011 and 2012, respectively, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFCH or TCEH, the issuers must offer to repurchase the TCEH Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

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EFH Corp. Senior Notes — EFH Corp.’s 10.875% Notes bear interest that is payable semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.875% per annum payable in cash. EFH Corp.’s Toggle Notes due November 1, 2017 bear interest semiannually 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. For any interest period until November 1, 2012, EFH Corp. may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFH Corp. Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Once EFH Corp. makes a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. revokes the election.

The EFH Corp. 10.875% and Toggle Notes (collectively, the EFH Corp. Senior Notes) had a total principal amount as of September 30, 2010 of $898 million (excluding $3.594 billion principal amount held by EFIH) and are fully and unconditionally guaranteed on a joint and several unsecured basis by EFCH and EFIH.

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

TCEH Interest Rate Swap Transactions — As of September 30, 2010, TCEH has entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $16.30 billion principal amount 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 2010 to 2014. No interest rate swap transactions have been entered into in 2010.

As of September 30, 2010, TCEH has entered into interest rate basis swap transactions pursuant to which payments at floating interest rates of three-month LIBOR on an aggregate of $16.30 billion principal amount of senior secured term loans of TCEH were exchanged for floating interest rates of one-month LIBOR plus spreads ranging from 0.0625% to 0.2055%. These transactions include swaps entered into in the nine months ended September 30, 2010 related to an aggregate $2.55 billion principal amount of senior secured term loans of TCEH and reflect the expiration of swaps in the nine months ended September 30, 2010 related to an aggregate $2.50 billion principal amount of senior secured term loans of TCEH.

The interest rate swap counterparties are proportionately secured by the same collateral package granted to the lenders under the TCEH Senior Secured Facilities. Changes in the fair value of such swaps are being reported in the income statement in interest expense and related charges, and such unrealized mark-to-market value changes totaled $181 million and $542 million in net losses in the three and nine months ended September 30, 2010, respectively, and $138 million in net losses and $527 million in net gains in the three and nine months ended September 30, 2009, respectively. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.755 billion as of September 30, 2010, of which $120 million (pre-tax) was reported in accumulated other comprehensive income.

See Note 11 for discussion of collateral investments related to certain of these interest rate swaps that expired in March 2010.

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7. COMMITMENTS AND CONTINGENCIES

Guarantees

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

Disposed TXU Gas operations — In connection with the sale of TXU Gas in October 2004, EFH Corp. agreed to indemnify Atmos Energy Corporation (Atmos), until October 1, 2014, for up to $500 million for any liability related to assets retained by TXU Gas, including certain inactive gas plant sites not acquired by Atmos, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximum aggregate amount under these indemnities that we may be required to pay is $1.9 billion. To date, we have not been required to make any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.

Residual value guarantees in operating leases — We are the lessee under various operating leases that guarantee the residual values of the leased assets. As of September 30, 2010, the aggregate maximum amount of residual values guaranteed was $13 million with an estimated residual recovery of $13 million. These leased assets consist primarily of rail cars. The average life of the residual value guarantees under the lease portfolio is approximately six years.

See Note 6 above and Note 12 to Financial Statements in the 2009 Form 10-K for discussion of guarantees and security for certain of our debt.

Letters of Credit

As of September 30, 2010, TCEH had outstanding letters of credit under its credit facilities totaling $725 million as follows:

• $325 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions;

• $208 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $204 million (the letters of credit are available to fund the payment of such debt obligations and expire in 2014);

• $84 million to support TCEH’s REP’s financial requirements with the PUCT, and

• $108 million for miscellaneous credit support requirements.

Litigation Related to Generation Facilities

In September 2007, 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 was filed in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. 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. Subsequently, the non-parties to the original administrative proceeding non-suited their claims, thus ending their legal challenge. In July 2010, the court issued an order rejecting the remaining plaintiff’s claims and upholding the TCEQ’s issuance of the Oak Grove air permit. The plaintiff did not appeal the court’s order. Accordingly, the matter has been resolved favorably for us, and the judgment in the case is now final.

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In July 2008, Alcoa Inc. filed a lawsuit in the State District Court of Milam County, Texas against Luminant Generation and Luminant Mining (wholly-owned subsidiaries of TCEH), later adding EFH Corp., a number of its subsidiaries, Texas Holdings and Texas Holdings’ general partner as parties to the suit. The lawsuit made various claims concerning the operation of the Sandow Unit 4 generation facility and the related Three Oaks lignite mine, including claims for breach of contract, breach of fiduciary duty, fraud, tortious interference, civil conspiracy and conversion. The plaintiff requested money damages of no less than $500 million, declaratory judgment, rescission and other forms of equitable relief. In May 2010, the trial court granted a summary judgment dismissing substantially all of Alcoa’s claims other than its breach of contract claims against Luminant Generation and Luminant Mining. On the breach of contract claims against Luminant Generation relating to the Sandow Unit 4 generation facility, a jury rendered a verdict in Luminant Generation’s favor in June 2010. The jury awarded no damages to Alcoa and awarded $10 million in damages to Luminant Generation. In June 2010, the judge presiding in the case ruled in Luminant Mining’s favor on the claims against it, awarding no damages to Alcoa and awarding nearly $2 million in damages to Luminant Mining. As a result, the lawsuit was concluded favorably to Luminant. Alcoa did not appeal the final judgment.

In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (Texarkana Division) against EFH Corp. and Luminant Generation Company LLC (a wholly-owned subsidiary of TCEH) for alleged violations of the Clean Air Act at Luminant’s Martin Lake generation facility. As previously disclosed, in July 2008, the Sierra Club had given Luminant notice of its intention to sue. While we are unable to estimate any possible loss or predict the outcome of the litigation, we believe that the Sierra Club’s claims are without merit, and we intend to vigorously defend this litigation. In addition, in February 2010, the Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Big Brown generation facility. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.

Regulatory Investigations and Reviews

In June 2008, the EPA issued a request for information to TCEH under the EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.

Sandow Power Company LLC (Sandow Power), a subsidiary of TCEH, is a party to a federal consent decree (the Consent Decree) with, among others, the US Department of Justice (DOJ) and certain private plaintiffs related to Sandow Power’s Sandow Unit 5 lignite-fueled generation facility. Between December 3, 2009 and March 31, 2010, Sandow Power submitted several force majeure claims to the DOJ regarding ostensible deviations from emissions limits at Sandow Unit 5 resulting from force majeure events, as that term is defined in the Consent Decree. In September 2010, Sandow Power, the DOJ, the EPA and the private plaintiffs filed with the court a notice of settlement regarding these force majeure claims, and the court subsequently issued an order approving that settlement. The settlement involves a payment to the US Treasury that is not material to the company, but in excess of the $100,000 disclosure threshold applicable to such matters.

Other Proceedings

In addition to the above, we 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 our financial position, results of operations or cash flows.

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8. EQUITY

Dividend Restrictions

The indentures governing the EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes include covenants that, among other things and subject to certain exceptions, restrict our ability to pay dividends or make other distributions in respect of our common stock. Accordingly, essentially all of our net income is restricted from being used to make distributions on our common stock unless such distributions are expressly permitted under these indentures and/or on a pro forma basis, after giving effect to such distribution, EFH Corp.’s consolidated leverage ratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, “consolidated leverage ratio” is defined as the ratio of consolidated total indebtedness (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiaries other than Oncor Holdings and its subsidiaries. In addition, the indenture governing the EFIH Notes generally restricts EFIH from making any cash distribution to EFH Corp. for the ultimate purpose of making a cash distribution on our common stock unless at the time, and after giving effect to such distribution, EFIH’s consolidated leverage ratio is equal to or less than 6.0 to 1.0. Under the indenture governing the EFIH Notes, the term “consolidated leverage ratio” is defined as the ratio of EFIH’s consolidated total indebtedness (as defined in the indenture) to EFIH’s Adjusted EBITDA on a consolidated basis (including Oncor’s Adjusted EBITDA).

The TCEH Senior Secured Facilities generally restrict TCEH from making any cash distribution to any of its parent companies for the ultimate purpose of making a cash distribution on our common stock unless at the time, and after giving effect to such distribution, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. In addition, the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes and TCEH Senior Secured Second Lien Notes generally restrict TCEH’s ability to make distributions or loans to any of its parent companies, EFCH and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and indenture governing the TCEH Senior Notes. Those agreements generally permit TCEH to make unlimited distributions or loans to its parent companies for corporate overhead costs, SG&A expenses, taxes and principal and interest payments. In addition, those agreements contain certain investment and dividend baskets that would allow TCEH to make additional distributions and/or loans to its parent companies up to the amount of such baskets. As of September 30, 2010, EFH Corp. demand notes payable to TCEH totaled $1.690 billion, of which $704 million is related to principal and interest payments. Such principal and interest amounts are guaranteed by EFCH and EFIH on a pari passu basis with their guarantees of the EFH Corp. Senior Notes; the remaining balance of the demand notes is not guaranteed.

In addition, under applicable law, we would be prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent.

EFH Corp. did not declare or pay any cash dividends in 2010 or 2009.

Distributions from Oncor — Until December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor’s net income determined in accordance with GAAP, subject to certain defined adjustments. Such adjustments include deducting the $72 million ($46 million after-tax) one-time refund to customers in September 2008, net accretion of fair value adjustments resulting from purchase accounting and funds spent as part of the $100 million commitment for additional demand-side management or other energy efficiency initiatives (see Note 6 to the 2009 Form 10-K Financial Statements) of which $35 million ($23 million after tax) has been spent through September 30, 2010, and removing the effects of the $860 million goodwill impairment charge from fourth quarter 2008 net income available for distribution. As a result, $9 million of Oncor’s $149 million net income earned in the three months ended September 30, 2010 was restricted from being used to make distributions of membership interests under the cumulative net income restriction.

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Oncor’s distributions are further limited by an agreement that its regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. As of September 30, 2010 and December 31, 2009, the regulatory capitalization ratio was 59.7% debt and 40.3% equity and 58.1% debt and 41.9% equity, respectively. The PUCT has the authority to determine what types of debt and equity are included in a utility’s debt-to-equity ratio. For purposes of this ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. The debt calculation excludes transition bonds issued by Oncor Electric Delivery Transition Bond Company. Equity is calculated as membership interests determined in accordance with GAAP, excluding the effects of accounting for the Merger (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization). Oncor is required to file a quarterly Earnings Monitor Report with the PUCT that sets forth its debt-to-equity ratio. This Earnings Monitor Report shall not be deemed a part of, or incorporated by reference into, these financial statements. Accordingly, as of September 30, 2010, $35 million of Oncor’s membership interests was available for distribution under the capital structure restriction, of which approximately 80% relates to EFH Corp.’s ownership interest.

Noncontrolling Interests

Of the noncontrolling interests balance as of December 31, 2009 in the table below, $1.363 billion related to Oncor. See Note 1 for discussion of the deconsolidation of Oncor in 2010. As of December 31, 2009 (and September 30, 2010), Oncor’s ownership was as follows: 80.03% held indirectly by EFH Corp., 0.22% held indirectly by Oncor’s management and board of directors and 19.75% held by Texas Transmission.

In connection with the filing of a combined operating license application with the NRC for two new nuclear generation units, in January 2009, TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, CPNPC, to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. Under the terms of the joint venture agreement, a subsidiary of TCEH owns an 88% interest in the venture and a subsidiary of MHI owns a 12% interest. This joint venture is a variable interest entity, and a subsidiary of TCEH is considered the primary beneficiary (see Note 3).

Equity

The following table presents the changes to equity during the nine months ended September 30, 2010.

	EFH Corp. Shareholders’ Equity
	Common Stock (a)		Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total Equity
Balance as of December 31, 2009	$	2	$	7,914		$	(10,854	)	$	(309	)	$	1,411		$	(1,836	)
Net loss		—		—			(2,973	)		—			—			(2,973	)
Effects of EFH Corp. stock-based incentive compensation plans		—		19			—			—			—			19
Change in unrecognized gains related to pension and OPEB costs		—		—			—			15			—			15
Net effects of cash flow hedges		—		—			—			49			—			49
Effects of deconsolidation of Oncor Holdings		—		—			—			—			(1,363	)		(1,363	)
Investment by noncontrolling interests		—		—			—			—			24			24
Stock repurchases		—		(2	)		—			—			—			(2	)
Other		—		—			—			—			(1	)		(1	)
Balance as of September 30, 2010	$	2	$	7,931		$	(13,827	)	$	(245	)	$	71		$	(6,068	)

(a) Authorized shares totaled 2,000,000,000 as of September 30, 2010. Outstanding shares totaled 1,669,277,542 and 1,668,065,133 as of September 30, 2010 and December 31, 2009, respectively.

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9. FAIR VALUE MEASUREMENTS

Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a “mid-market” valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.

We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:

• Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities include exchange traded commodity contracts. For example, a significant number of our derivatives are NYMEX futures and swaps transacted through clearing brokers for which prices are actively quoted.

• Level 2 valuations use inputs, in the absence of actively quoted market prices, that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means and other valuation inputs. For example, our Level 2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes are available.

• Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assets and liabilities include certain derivatives whose values are derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means.

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.

In utilizing broker quotes, we attempt to obtain multiple quotes from brokers that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker’s publication policy, recent trading volume trends and various other factors. In addition, for valuation of interest rate swaps, we use a combination of dealer provided market valuations (generally non-binding) and Bloomberg valuations based on month-end interest rate curves and standard rate swap valuation models.

Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including commodity prices, volatility factors, discount rates and other inputs. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Those valuation models are generally used in developing long-term forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.

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With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.

As of September 30, 2010, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3 (a)		Reclassification(b)		Total
Assets:
Commodity contracts	$	1,165	$	4,166	$	538	$	62	$	5,931
Interest rate swaps		—		142		—		—		142
Nuclear decommissioning trust — equity securities (c)		170		109		—		—		279
Nuclear decommissioning trust — debt securities (c)		—		229		—		—		229
Total assets	$	1,335	$	4,646	$	538	$	62	$	6,581
Liabilities:
Commodity contracts	$	1,350	$	866	$	284	$	62	$	2,562
Interest rate swaps		—		1,925		—		—		1,925
Total liabilities	$	1,350	$	2,791	$	284	$	62	$	4,487

(a) Level 3 assets and liabilities consist primarily of complex long-term power purchase and sales agreements, including a long-term wind generation purchase contract, certain natural gas positions (collars) in the long-term hedging program and certain power transactions valued at illiquid pricing locations as discussed below.

(b) Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities.

(c) The nuclear decommissioning trust investment is included in the other investments line on the balance sheet. See Note 16.

As ERCOT transitions to a nodal wholesale market structure, we have entered (and expect to increasingly enter) into certain derivative transactions that are valued at illiquid pricing locations (unobservable inputs), thus requiring classification as Level 3 assets or liabilities. As the nodal market matures and more transactions and pricing information becomes available for these pricing locations, we expect more of the valuation inputs to become observable.

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As of December 31, 2009, assets and liabilities measured at fair value on a recurring basis consisted of the following:

	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	918	$	2,588	$	350	$	4	$	3,860
Interest rate swaps		—		64		—		—		64
Nuclear decommissioning trust — equity securities (c) equity securities (c)		154		105		—		—		259
Nuclear decommissioning trust — debt securities (c) debt securities (c)		—		216		—		—		216
Total assets	$	1,072	$	2,973	$	350	$	4	$	4,399
Liabilities:
Commodity contracts	$	1,077	$	796	$	269	$	4	$	2,146
Interest rate swaps		—		1,306		—		—		1,306
Total liabilities	$	1,077	$	2,102	$	269	$	4	$	3,452

(a) Level 3 assets and liabilities consist primarily of complex long-term power purchase and sales agreements, including a long-term wind generation purchase contract and certain natural gas positions (collars) in the long-term hedging program.

(b) Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities.

(c) The nuclear decommissioning trust investment is included in the other investments line on the balance sheet. See Note 16.

Commodity contracts consist primarily of natural gas, electricity, fuel oil and coal derivative instruments entered into for hedging purposes and include physical contracts that have not been designated “normal” purchases or sales. See Note 11 for further discussion regarding the company’s use of derivative instruments.

Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 6 for discussion of interest rate swaps.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

There were no significant transfers between the levels of the fair value hierarchy for the three and nine months ended September 30, 2010.

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The following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts) for the three and nine months ended September 30, 2010 and 2009:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Balance as of beginning of period	$	169		$	(72	)	$	81		$	(72	)
Total realized and unrealized gains (losses) (a):
Included in net income (loss)		118			42			182			57
Included in other comprehensive income (loss)		—			(6	)		—			(31	)
Purchases, sales, issuances and settlements (net) (b)		(24	)		(6	)		7			(15	)
Transfers into Level 3 (c)		(11	)		1			(10	)		1
Transfers out of Level 3 (c)		2			—			(6	)		19
Balance as of end of period	$	254		$	(41	)	$	254		$	(41	)
Net change in unrealized gains (losses) included in net income relating to instruments held as of end of period	$	116		$	44		$	199		$	61

(a) Substantially all changes in values of commodity contracts are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

(b) Settlements represent reversals of unrealized mark-to-market valuations of these positions previously recognized in net income. Purchases and issuances reflect option premiums paid or received.

(c) Includes transfers due to changes in the observability of significant inputs. For 2010, in accordance with new accounting guidance issued by the FASB in January 2010, transfers in and out occur at the end of each quarter, which is when the assessments are performed. Prior period transfers in were assumed to transfer in at the beginning of the quarter and transfers out at the end of the quarter.

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10. FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of significant nonderivative financial instruments as of September 30, 2010 and December 31, 2009 were as follows:

	September 30, 2010				December 31, 2009
	Carrying Amount		Fair Value (a)		Carrying Amount		Fair Value (a)
On balance sheet liabilities:
Long-term debt (including current maturities) (b):
TCEH, EFH Corp., and other	$	35,336	$	26,835	$	36,600	$	29,115
Oncor (c)	$	—	$	—	$	5,104	$	5,644
Total	$	35,336	$	26,835	$	41,704	$	34,759
Off balance sheet liabilities:
Financial guarantees	$	—	$	4	$	—	$	6

(a) Fair value determined in accordance with accounting standards related to the determination of fair value.

(b) Excludes capital leases.

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

See Notes 9 and 11 for discussion of accounting for financial instruments that are derivatives.

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11. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

We enter into physical and financial derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a long-term commodity hedging program and the hedging of interest costs on our long-term debt. See Note 9 for a discussion of the fair value of all derivatives.

Long-Term Hedging Program — TCEH 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, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity is highly correlated to the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas through 2014. These transactions are intended to hedge a majority of electricity price exposure related to expected baseload generation for this period. Changes in the fair value of the instruments under the long-term hedging program are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

Interest Rate Swap Transactions — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swaps are used to effectively reduce the hedged borrowing costs. Changes in the fair value of the swaps are recorded as unrealized gains and losses in interest expense and related charges. See Note 6 for additional information about interest rate swap agreements.

Other Commodity Hedging and Trading Activity — In addition to the long-term hedging program, TCEH enters into derivatives, including electricity, natural gas, fuel oil and coal instruments, generally for shorter-term hedging purposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets.

Financial Statement Effects of Derivatives

Substantially all commodity and other derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of commodity and other derivative contractual assets and liabilities as reported in the balance sheets as of September 30, 2010 and December 31, 2009:

September 30, 2010
	Derivative assets					Derivative liabilities
	Commodity contracts			Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	3,364		$	141	$	15		$	—		$	3,520
Noncurrent assets		2,518			1		34			—			2,553
Current liabilities		(6	)		—		(2,258	)		(801	)		(3,065	)
Noncurrent liabilities		(7	)		—		(291	)		(1,124	)		(1,422	)
Net assets (liabilities)	$	5,869		$	142	$	(2,500	)	$	(1,925	)	$	1,586

December 31, 2009
	Derivative assets				Derivative liabilities
	Commodity contracts		Interest rate swaps		Commodity contracts			Interest rate swaps			Total
Current assets	$	2,327	$	60	$	4		$	—		$	2,391
Noncurrent assets		1,529		4		—			—			1,533
Current liabilities		—		—		(1,705	)		(687	)		(2,392	)
Noncurrent liabilities		—		—		(441	)		(619	)		(1,060	)
Net assets (liabilities)	$	3,856	$	64	$	(2,142	)	$	(1,306	)	$	472

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As of September 30, 2010 and December 31, 2009, there were no derivative positions accounted for as cash flow or fair value hedges.

Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled $503 million and $358 million in net liabilities as of September 30, 2010 and December 31, 2009, respectively, which do not include the collateral investments related to certain interest rate swaps and commodity positions discussed immediately below. Reported amounts as presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positions with the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.

In 2009, we entered into collateral funding transactions with counterparties to certain interest rate swap agreements related to TCEH debt. Under the terms of these transactions, which we elected to enter into as a cash management measure, as of December 31, 2009, EFH Corp. (parent) had posted $400 million in cash and TCEH had posted $65 million in letters of credit to the counterparties, with the outstanding balance of such collateral earning interest. TCEH had also entered into commodity hedging transactions with one of these counterparties, and under an arrangement effective August 2009, both the interest rate swaps and certain of the commodity hedging transactions with the counterparty are under the same derivative agreement, which continues to be secured by a first-lien interest in the assets of TCEH. In accordance with the agreements, the counterparties returned the collateral, along with accrued interest, on March 31, 2010. As of December 31, 2009, the cash collateral was recorded as an investment and was presented in the balance sheet (including accrued interest) as a separate line item under current assets.

The following table presents the pre-tax effect on net income of derivatives not under hedge accounting, including realized and unrealized effects:

	Three Months Ended September 30,						Nine Months Ended September 30,
Derivative (Income statement presentation)	2010			2009			2010			2009
Commodity contracts (Net gain from commodity hedging and trading activities)	$	979		$	136		$	2,255		$	1,026
Interest rate swaps (Interest expense and related charges)		(350	)		(317	)		(1,048	)		16
Net gain (loss)	$	629		$	(181	)	$	1,207		$	1,042

The following tables present the pre-tax effect on net income and other comprehensive income (OCI) of derivative instruments previously accounted for as cash flow hedges:

	Amount of gain (loss) recognized in OCI (effective portion)				Income statement presentation of loss reclassified from accumulated OCI into income (effective portion)	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
Derivative	Three Months Ended September 30, 2009		Nine Months Ended September 30, 2009
Interest rate swaps	$	—	$	—	Interest expense and related charges	$	(19	)	$	(72	)
					Depreciation and amortization		(1	)		(1	)
Commodity contracts		—		—	Fuel, purchased power costs and delivery fees		—			—
					Operating revenues		—			(1	)
Total	$	—	$	—		$	(20	)	$	(74	)

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Derivative	Amount of gain (loss) recognized in OCI (effective portion)						Income statement presentation of loss reclassified from accumulated OCI into income (effective portion)	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
Interest rate swaps	$	—		$	—		Interest expense and related charges	$	(56	)	$	(140	)
Commodity contracts		(6	)		(31	)	Fuel, purchased power costs and delivery fees		(6	)		(10	)
							Operating revenues		—			(2	)
Total	$	(6	)	$	(31	)		$	(62	)	$	(152	)

There were no transactions designated as cash flow hedges during the three and nine months ended September 30, 2010. There were no ineffectiveness net gains or losses related to transactions designated as cash flow hedges in the three and nine months ended September 30, 2009.

Accumulated other comprehensive income related to cash flow hedges as of September 30, 2010 and December 31, 2009 totaled $79 million and $128 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps. We expect that $26 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of September 30, 2010 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

Derivative Volumes

The following table presents the gross notional amounts of derivative volumes as of September 30, 2010 and December 31, 2009:

	September 30, 2010		December 31, 2009
Derivative type	Notional Volume				Unit of Measure
Interest rate swaps:
Floating/fixed	$	18,000	$	18,000		Million US dollars
Basis	$	16,300	$	16,250		Million US dollars
Natural gas:
Long-term hedge forward sales and purchases (a)		2,727		3,402		Million MMBtu
Locational basis swaps		1,006		1,010		Million MMBtu
All other		1,094		1,433		Million MMBtu
Electricity		172,010		198,230		GWh
Coal		7		6		Million tons
Fuel oil		116		161		Million gallons

(a) Represents gross notional forward sales, purchases and options of fixed and basis (price point) transactions in the long-term hedging program. The net amount of these transactions, excluding basis transactions, was 1.25 billion MMBtu and 1.6 billion MMBtu as of September 30, 2010 and December 31, 2009, respectively.

Credit Risk-Related Contingent Features of Derivatives

The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of those agreements require the posting of collateral if our credit rating is downgraded by one or more of the credit rating agencies; however, due to our credit ratings being below investment grade, substantially all of such collateral posting requirements are already effective.

As of September 30, 2010 and December 31, 2009, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $620 million and $687 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $94 million and $152 million as of September 30, 2010 and December 31, 2009, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of September 30, 2010 and December 31, 2009, the remaining related liquidity requirement would have totaled $24 million and $20 million, respectively, after reduction for net accounts receivable and derivative assets under netting arrangements.

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In addition, certain derivative agreements that are collateralized primarily with asset liens include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. As of September 30, 2010 and December 31, 2009, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $2.358 billion and $1.482 billion, respectively, (before consideration of the amount of assets under the liens). No cash collateral or letters of credit were posted with these counterparties as of September 30, 2010 to reduce the liquidity exposure, but $489 million of such collateral was posted as of December 31, 2009, with the decline reflecting the return of collateral from counterparties to certain interest rate swaps related to TCEH debt as discussed above in this note. If all the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, had been triggered as of September 30, 2010 and December 31, 2009, the remaining related liquidity requirement would have totaled $1.124 billion and $480 million, respectively, after reduction for derivative assets under netting arrangements (before consideration of the amount of assets under the liens). See Note 12 to Financial Statements in the 2009 Form 10-K for a description of other obligations that are supported by asset liens.

As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $2.978 billion and $2.169 billion as of September 30, 2010 and December 31, 2009, respectively. This amount is before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets under related liens.

Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.

Concentrations of Credit Risk Related to Derivatives

TCEH has significant concentrations of credit risk with the counterparties to its derivative contracts. As of September 30, 2010, total credit risk exposure to all counterparties related to derivative contracts totaled $6.1 billion (including associated accounts receivable). The net exposure to those counterparties totaled $2.2 billion as of September 30, 2010 after taking into effect master netting arrangements, setoff provisions and collateral. The net exposure, assuming setoff provisions in the event of default across all EFH Corp. consolidated subsidiaries, totaled $1.6 billion. As of September 30, 2010, the credit risk exposure to the banking and financial sector represented 94% of the total credit risk exposure, a significant amount of which is related to the long-term hedging program, and the largest net exposure to a single counterparty totaled approximately $1.0 billion. Exposure to the banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because substantially all of this exposure is with counterparties with credit ratings of “A” or better. However, this concentration increases the risk that a default by any of these counterparties would have a material adverse effect on our financial condition and results of operations.

The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies 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. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. 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. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.

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12. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) COSTS

Net pension and OPEB costs for the three and nine months ended September 30, 2010 and 2009 are comprised of the following:

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
Components of net pension costs:
Service cost	$	11		$	10		$	32		$	28
Interest cost		41			40			120			119
Expected return on assets		(40	)		(41	)		(120	)		(124	)
Amortization of prior service cost		—			—			—			—
Amortization of net loss		15			4			42			7
Net pension costs		27			13			74			30
Components of net OPEB costs:
Service cost		3			3			9			8
Interest cost		16			15			46			46
Expected return on assets		(5	)		(3	)		(11	)		(10	)
Amortization of transition obligation		—			—			1			—
Amortization of prior service cost		—			—			(1	)		—
Amortization of net loss		6			3			16			9
Net OPEB costs		20			18			60			53
Total net pension and OPEB costs		47			31			134			83
Less amounts expensed by Oncor		(9	)		—			(27	)		—
Less amounts deferred principally as a regulatory asset or property by Oncor		(23	)		(18	)		(66	)		(51	)
Amount recognized as expense by EFH Corp. and consolidated subsidiaries	$	15		$	13		$	41		$	32

The discount rate reflected in net pension and OPEB costs in 2010 is 5.90%. The expected rates of return on pension and OPEB plan assets reflected in the 2010 cost amounts are 8.0% and 7.6%, respectively.

We made cash contributions related to our pension and OPEB plans totaling $28 million and $17 million, respectively, in the first nine months of 2010, of which $40 million was contributed by Oncor. We expect to make additional contributions of $15 million and $7 million, respectively, in the remainder of 2010, of which $17 million is expected to be contributed by Oncor.

13. EFFECT OF HEALTH CARE LEGISLATION

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act enacted in March 2010 reduces, effective in 2013, the amount of OPEB costs deductible for federal income tax purposes by the amount of the Medicare Part D subsidy we receive. Under income tax accounting rules, deferred tax assets related to accrued OPEB liabilities must be reduced immediately for the future effect of the legislation. Accordingly, in the three months ended March 31, 2010, EFH Corp.’s and Oncor’s deferred tax assets were reduced by $50 million. Of this amount, $8 million was recorded as a charge to income tax expense and $42 million was recorded as a regulatory asset by Oncor (before gross-up for liability in lieu of deferred income taxes) as the additional income taxes are expected to be recoverable in Oncor’s future rates.

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14. RELATED PARTY TRANSACTIONS

The following represent the significant related-party transactions of EFH Corp.:

• We incur an annual management fee under the terms of a management agreement with the Sponsor Group for which we accrued $9 million for both the three months ended September 30, 2010 and 2009, and $27 million for both the nine months ended September 30, 2010 and 2009. The fee is reported as SG&A expense.

• In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of GS Capital Partners and Kohlberg Kravis Roberts & Co. L.P. (a member of the Sponsor Group) have from time to time engaged in commercial banking and financial advisory transactions with us in the normal course of business.

• Fees paid to Goldman, Sachs & Co. (Goldman) related to debt issuances and exchanges total $11 million in 2010 through October, described as follows. Goldman acted as an initial purchaser in the issuance of $500 million principal amount of EFH Corp. 10% Notes in January 2010 as discussed in Note 6 and received fees totaling $3 million. Goldman acted as a dealer manager and solicitation agent in the debt exchange offers completed in August 2010 as discussed in Note 6 and received fees of $7 million. Goldman also acted as an initial purchaser in the issuance of $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) in October 2010 as discussed in Note 6 and received fees totaling $1 million.

• Affiliates of Goldman Sachs & Co. are parties to certain commodity and interest rate hedging transactions with us in the normal course of business.

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

• TCEH’s retail operations incur electricity delivery fees charged by Oncor, which totaled $317 million and $839 million for the three and nine months ended September 30, 2010, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheet as of September 30, 2010 reflects amounts due currently to Oncor totaling $182 million (included in net payables due to unconsolidated subsidiary), primarily related to these electricity delivery fees.

• Oncor’s bankruptcy-remote financing subsidiary has issued securitization bonds to recover generation-related regulatory assets through a transition surcharge to its customers. Oncor’s incremental income taxes related to the transition surcharges it collects are being reimbursed by TCEH. Therefore, the balance sheet reflects a noninterest bearing note payable to Oncor of $227 million ($38 million current portion included in net payables due to unconsolidated subsidiary) as of September 30, 2010.

• TCEH reimburses Oncor for interest expense on Oncor’s bankruptcy-remote financing subsidiary’s securitization bonds. This interest expense totaled $9 million and $28 million for the three and nine months ended September 30, 2010, respectively.

• A subsidiary of EFH Corp. charges Oncor for financial and other administrative services at cost, which totaled $9 million and $27 million for the three and nine months ended September 30, 2010, respectively.

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility, reported in other investments on the balance sheet, is funded by a delivery fee surcharge billed to REPs by Oncor and remitted to TCEH, with the intent that the trust fund assets will be sufficient to fund the decommissioning liability, reported in noncurrent liabilities on the balance sheet. Income and expenses associated with the trust fund and the decommissioning liability incurred by us are offset by a net change in the intercompany receivable/payable with Oncor, which in turn results in a change in Oncor’s net regulatory asset/liability. As of September 30, 2010, the excess of the trust fund balance over the decommissioning liability resulted in a payable to Oncor totaling $183 million included in noncurrent liabilities due to unconsolidated subsidiary in the balance sheet.

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The intercompany receivable/payable with Oncor has changed from a receivable of $85 million as of January 1, 2010 to a payable of $183 million as of September 30, 2010 due to a new decommissioning cost estimate completed in the second quarter 2010 that resulted in a decline of the liability. The new cost estimate was completed in accordance with regulatory requirements to perform a cost estimate every five years. The lower estimated liability was driven by lower cost escalation assumptions in the new estimate. (Also see Note 16 under “Asset Retirement Obligations.”)

• We file a consolidated federal income tax return; however, Oncor Holdings’ federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., are recorded as if Oncor Holdings files its own income tax return. As of September 30, 2010, the amount due to Oncor Holdings totaled $59 million and is included in net payables due to unconsolidated subsidiary.

• Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, as of September 30, 2010, TCEH had posted a letter of credit in the amount of $14 million for the benefit of Oncor.

• EFH Corp. and Oncor are jointly and severally liable for the funding of the EFH Corp. pension plan and a portion of the OPEB plan obligations. EFH Corp. is liable for the majority of the OPEB plan obligations. Oncor has contractually agreed to reimburse EFH Corp. with respect to certain pension plan and OPEB liabilities. Accordingly, as of September 30, 2010, the balance sheet of EFH Corp. reflects such unfunded liabilities and a corresponding receivable from Oncor in the amount of $1.270 billion, classified as noncurrent, which represents the portion of the obligations recoverable by Oncor under regulatory rate-setting provisions and reported by Oncor in its balance sheet.

• Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter of credit in an amount equal to $170 million to secure its payment obligations to Oncor if two or more rating agencies downgrade Oncor’s credit ratings below investment grade.

15. SEGMENT INFORMATION

Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.

The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales to residential and business customers, all largely in Texas. These activities are conducted by TCEH.

The Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly-owned bankruptcy-remote financing subsidiary. See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings and, accordingly, the Regulated Delivery segment, effective as of January 1, 2010.

Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued businesses, general corporate expenses and interest on EFH Corp. (parent entity), EFIH and EFCH debt.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 above and in Note 1 in the 2009 Form 10-K. We evaluate performance based on income from continuing operations. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.

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	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
Operating revenues:
Competitive Electric	$	2,607		$	2,433		$	6,599		$	6,144
Regulated Delivery		—			770			—			2,037
Corporate and Other		—			3			—			16
Eliminations		—			(321	)		—			(831	)
Consolidated	$	2,607		$	2,885		$	6,599		$	7,366
Affiliated revenues included in operating revenues:
Competitive Electric	$	—		$	2		$	—		$	5
Regulated Delivery		—			316			—			813
Corporate and Other		—			3			—			13
Eliminations		—			(321	)		—			(831	)
Consolidated	$	—		$	—		$	—		$	—
Equity in earnings of unconsolidated subsidiaries (net of tax):
Regulated Delivery	$	118		$	—		$	240		$	—
Net income (loss):
Competitive Electric	$	(3,710	)	$	(44	)	$	(3,705	)	$	436
Regulated Delivery		118			132			240			272
Corporate and Other		690			(142	)		492			(447	)
Consolidated	$	(2,902	)	$	(54	)	$	(2,973	)	$	261

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16. SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations

	Three Months  Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Operating revenues
Regulated	$	—		$	770		$	—		$	2,037
Unregulated		2,607			2,436			6,599			6,160
Intercompany sales eliminations – regulated		—			(316	)		—			(813	)
Intercompany sales eliminations – unregulated		—			(5	)		—			(18	)
Total operating revenues		2,607			2,885			6,599			7,366
Fuel, purchased power and delivery fees – unregulated (a)		(1,400	)		(870	)		(3,521	)		(2,171	)
Net gain from commodity hedging and trading activities – unregulated		992			123			2,272			1,003
Operating costs – regulated		—			(228	)		—			(668	)
Operating costs – unregulated		(197	)		(160	)		(623	)		(503	)
Depreciation and amortization – regulated		—			(147	)		—			(405	)
Depreciation and amortization – unregulated		(352	)		(309	)		(1,043	)		(881	)
Selling, general and administrative expenses – regulated		—			(50	)		—			(139	)
Selling, general and administrative expenses – unregulated		(187	)		(227	)		(560	)		(653	)
Franchise and revenue-based taxes – regulated		—			(67	)		—			(185	)
Franchise and revenue-based taxes – unregulated		(24	)		(27	)		(73	)		(74	)
Impairment of goodwill		(4,100	)		—			(4,100	)		(90	)
Other income		1,033			45			1,278			71
Other deductions		(4	)		(32	)		(23	)		(50	)
Interest income		—			18			9			30
Interest expense and other charges		(1,018	)		(1,039	)		(3,092	)		(2,136	)
Income (loss) before income taxes and equity in earnings of unconsolidated subsidiaries	$	(2,650	)	$	(85	)	$	(2,877	)	$	515

(a) Includes unregulated cost of fuel consumed of $414 million and $360 million for the three months ended September 30, 2010 and 2009, respectively, and $1.094 billion and $943 million for the nine months ended September 30, 2010 and 2009, respectively. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.

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Other Income and Deductions

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Other income:
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting	$	—	$	10	$	—	$	30
Debt extinguishment gains (Note 6) (a)		1,023		—		1,166		—
Gain on sale of interest in natural gas gathering pipeline business (b)		—		—		37		—
Gain on sale of land/water rights (b)		—		—		44		—
Reversal of reserve recorded in purchase accounting (c)		—		23		—		23
Fee received related to interest rate swap/commodity hedge derivative agreement (b) (Note 11)		—		6		—		6
Office space rental income (a)		3		—		9		—
Insurance/litigation settlements (b)		6		—		6		—
Sales tax refund		—		3		5		3
Other		1		3		11		9
Total other income	$	1,033	$	45	$	1,278	$	71
Other deductions:
Write-off of regulatory assets (d)	$	—	$	25	$	—	$	25
Ongoing pension and OPEB expense related to discontinued businesses		1		—		6		—
Severance charges		—		—		2		6
Net charges related to cancelled development of generation facilities		—		1		2		3
Other		3		6		13		16
Total other deductions	$	4	$	32	$	23	$	50

(a) Reported in Corporate and Other segment.

(b) Reported in Competitive Electric segment.

(c) Reversal of a use tax accrual, related to periods prior to the Merger, due to a state ruling in 2009 (reported in Competitive Electric segment).

(d) The PUCT’s order in Oncor’s rate review in 2009 resulted in the denial of recovery of certain regulatory assets, primarily related to business restructuring costs and rate case expenses (reported in Regulated Delivery segment).

Interest Expense and Related Charges

	Three Months  Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps)	$	672		$	743		$	1,999		$	2,232
Accrued interest to be paid with additional toggle notes (Note 6)		106			131			384			387
Unrealized mark-to-market net (gain) loss on interest rate swaps		181			138			542			(527	)
Amortization of interest rate swap losses at dedesignation of hedge accounting		19			56			72			140
Amortization of fair value debt discounts resulting from purchase accounting		14			17			49			56
Amortization of debt issuance costs and discounts		32			34			99			104
Capitalized interest		(6	)		(80	)		(53	)		(256	)
Total interest expense and related charges	$	1,018		$	1,039		$	3,092		$	2,136

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Restricted Cash

	September 30, 2010				December 31, 2009
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to TCEH’s Letter of Credit Facility (See Note 6)	$	—	$	1,135	$	—	$	1,135
Amounts related to margin deposits held		31		—		1		—
Amounts related to securitization (transition) bonds		—		—		47		14
Total restricted cash	$	31	$	1,135	$	48	$	1,149

Inventories by Major Category

	September 30,		December 31,
	2010		2009
Materials and supplies (a)	$	164	$	248
Fuel stock		197		204
Natural gas in storage		27		33
Total inventories	$	388	$	485

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

Other Investments

	September 30, 2010		December 31, 2009
Nuclear decommissioning trust	$	508	$	475
Assets related to employee benefit plans, including employee savings programs, net of distributions (a)		114		184
Land		41		43
Miscellaneous other		4		4
Total investments	$	667	$	706

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

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 Oncor’s regulatory asset/liability. A summary of investments in the fund follows:

	September 30, 2010
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	219	$	12	$	(2	)	$	229
Equity securities (c)		208		90		(19	)		279
Total	$	427	$	102	$	(21	)	$	508

	December 31, 2009
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	211	$	8	$	(3	)	$	216
Equity securities (c)		195		83		(19	)		259
Total	$	406	$	91	$	(22	)	$	475

(a) Includes realized gains and losses of securities sold.

(b) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.53% and 4.44% and an average maturity of 7.9 years and 7.8 years as of September 30, 2010 and December 31, 2009, respectively.

(c) The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.

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Debt securities held as of September 30, 2010 mature as follows: $80 million in one to five years, $42 million in five to ten years and $107 million after ten years.

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.

	Nine Months Ended September 30,
	2010			2009
Realized gains	$	1		$	1
Realized losses		(1	)		(4	)
Proceeds from sale of securities		937			2,972

Property, Plant and Equipment

As of September 30, 2010 and December 31, 2009, property, plant and equipment of $20.5 billion and $30.1 billion, respectively, is stated net of accumulated depreciation and amortization of $3.9 billion and $7.1 billion, respectively.

Asset Retirement Obligations

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to the recognition of the asset retirement costs for nuclear decommissioning, as all costs are recoverable through the regulatory process as part of Oncor’s rates.

The following table summarizes the changes to the asset retirement liability, reported in other current liabilities and other noncurrent liabilities and deferred credits in the balance sheet, during the nine months ended September 30, 2010:

Asset retirement liability as of January 1, 2010	$	948
Additions:
Accretion		46
Reductions:
Payments, essentially all mining reclamation		(33	)
Adjustment for new cost estimate (a)		(498	)
Asset retirement liability as of September 30, 2010		463
Less amounts due currently		(35	)
Noncurrent asset retirement liability as of September 30, 2010	$	428

(a) Essentially all of the adjustment relates to the nuclear decommissioning liability, which resulted from a new cost estimate completed in the second quarter 2010. In accordance with regulatory requirements, a new cost estimate is completed every five years. A decline in the liability was driven by lower cost escalation assumptions in the new estimate. The reduction in the liability was offset in part by a reduction in the carrying value of the nuclear facility with the balance offset by an increase in the noncurrent liability to Oncor, which in turn resulted in a regulatory liability on Oncor’s balance sheet. (Also see Note 14.)

F-144

Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:

	September 30, 2010		December 31, 2009
Uncertain tax positions (including accrued interest)	$	1,824	$	1,999
Retirement plan and other employee benefits		1,656		1,711
Asset retirement obligations		428		948
Unfavorable purchase and sales contracts		680		700
Liabilities related to subsidiary tax sharing agreement (a)		—		321
Other		39		87
Total other noncurrent liabilities and deferred credits	$	4,627	$	5,766

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

During the third quarter 2010, we engaged in negotiations with the Internal Revenue Service (IRS) regarding a worthlessness loss associated with our discontinued Europe business as well as other matters. Accordingly, we have adjusted the liability for uncertain tax positions to reflect the most likely settlement of the issues. The adjustment resulted in a net reduction of the liability for uncertain tax positions totaling $162 million. This reduction consisted of a $225 million reversal of accrued interest ($146 million after tax), reported as a reduction of income tax expense, principally related to the discontinued Europe business, partially offset by $63 million in adjustments related to several other positions that have been accounted for as reclassifications to net deferred tax liabilities. The conclusion of all issues contested from the 1997 through 2002 audit, including IRS Joint Committee review, is not expected to occur prior to 2011. Upon such conclusion, we expect to further reduce the liability for uncertain tax positions by approximately $700 million with an offsetting decrease in deferred tax assets that arose largely from previous payments of alternative minimum taxes. No cash income tax liability is expected related to the conclusion of the 1997 through 2002 audit.

Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $7 million in both the three months ended September 30, 2010 and 2009 and $20 million and $21 million in the nine months ended September 30, 2010 and 2009, respectively. Favorable purchase and sales contracts are recorded as intangible assets (see Note 4).

The estimated amortization of unfavorable purchase and sales contracts for each of the five fiscal years from December 31, 2009 is as follows:

Year	Amount
2010	$	27
2011		27
2012		27
2013		26
2014		25

F-145

Supplemental Cash Flow Information

	Nine Months  Ended September 30,
	2010			2009
Cash payments (receipts) related to:
Interest paid (a)	$	1,770		$	2,042
Capitalized interest		(53	)		(256	)
Interest paid (net of capitalized interest) (a)		1,717			1,786
Income taxes		64			(38	)
Noncash investing and financing activities:
Noncash construction expenditures (b)		38			132
Capital leases		9			15

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

(b) Represents end-of-period accruals.

See Note 6 for noncash exchanges of debt.

F-146

17. SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

As of September 30, 2010, EFH Corp. had outstanding $359 million principal amount of EFH Corp. 10.875% Notes and $539 million principal amount of EFH Corp. Toggle Notes (collectively, the EFH Corp. Senior Notes) and $115 million principal amount of EFH Corp. 9.75% Notes and $1.061 billion principal amount of EFH Corp. 10% Notes (collectively, the EFH Corp. Senior Secured Notes). The EFH Corp. Senior Notes and Senior Secured Notes are unconditionally guaranteed by EFCH and EFIH, 100% owned subsidiaries of EFH Corp. (collectively, the Guarantors) on an unsecured basis except for EFIH’s guarantee of the EFH Corp. Senior Secured Notes, which is secured by a pledge of all membership interests and other investments EFIH owns or holds in Oncor Holdings or any of Oncor Holdings’ subsidiaries as described in Note 6. The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the EFH Corp. Senior Notes and Senior Secured Notes. The guarantees by EFCH and the guarantee of the EFH Corp. Senior Notes by EFIH 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. Senior Notes and EFH Corp. Senior Secured Notes (collectively, the Non-Guarantors). The indentures governing the EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes contain certain restrictions, subject to certain exceptions, on EFH Corp.’s ability to pay dividends or make investments. See Note 8.

The following tables have been prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered” in order to present the condensed consolidating statements of income of EFH Corp. (the Parent/Issuer), the Guarantors and the Non-Guarantors for the three-month and nine-month periods ended September 30, 2010 and 2009, 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, 2010 and 2009 and the consolidating balance sheets as of September 30, 2010 and December 31, 2009 of the Parent/Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5-J, “Push Down Basis of Accounting Required in Certain Limited Circumstances,” including the effects of the push down of the $898 million and $4.63 billion principal amount of EFH Corp. Senior Notes and $771 million and $115 million principal amount of the EFH Corp. Senior Secured Notes to the Guarantors as of September 30, 2010 and December 31, 2009, respectively (see Note 6). Amounts pushed down reflect Merger-related debt and additional debt guaranteed by the Guarantors that was issued by EFH Corp. to refinance Merger-related or other debt existing at the time of the Merger.

EFH Corp. (Parent) received dividends from its subsidiaries totaling $2 million and $117 million for the nine months ended September 30, 2010 and 2009, respectively.

F-147

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Three Months Ended September 30, 2010

(millions of dollars)

	Parent/ Issuer			Guarantors			Non- Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	2,607		$	—		$	2,607
Fuel, purchased power costs and delivery fees		—			—			(1,400	)		—			(1,400	)
Net gain from commodity hedging and trading activities		—			—			992			—			992
Operating costs		—			—		��	(197	)		—			(197	)
Depreciation and amortization		—			—			(352	)		—			(352	)
Selling, general and administrative expenses		(6	)		—			(181	)		—			(187	)
Franchise and revenue-based taxes		—			—			(24	)		—			(24	)
Impairment of goodwill		—			—			(4,100	)		—			(4,100	)
Other income		75			—			10			948			1,033
Other deductions		—			—			(5	)		1			(4	)
Interest income		55			72			79			(206	)		—
Interest expense and related charges		(271	)		(136	)		(899	)		288			(1,018	)
Income (loss) before income taxes and equity in earnings of subsidiaries		(147	)		(64	)		(3,470	)		1,031			(2,650	)
Income tax (expense) benefit		85			32			(109	)		(378	)		(370	)
Equity in earnings of consolidated subsidiaries		(2,958	)		(3,690	)		—			6,648			—
Equity in earnings of unconsolidated subsidiaries (net of tax)		118			118			—			(118	)		118
Net income (loss)		(2,902	)		(3,604	)		(3,579	)		7,183			(2,902	)
Net income attributable to noncontrolling interests		—			—			—			—			—
Net income (loss) attributable to EFH Corp.	$	(2,902	)	$	(3,604	)	$	(3,579	)	$	7,183		$	(2,902	)

F-148

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Three Months Ended September 30, 2009

(millions of dollars)

	Parent/ Issuer			Guarantors			Non- Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	2,885		$	—		$	2,885
Fuel, purchased power costs and delivery fees		—			—			(870	)		—			(870	)
Net gain from commodity hedging and trading activities		—			—			123			—			123
Operating costs		—			—			(388	)		—			(388	)
Depreciation and amortization		—			—			(456	)		—			(456	)
Selling, general and administrative expenses		(29	)		—			(248	)		—			(277	)
Franchise and revenue-based taxes		—			—			(94	)		—			(94	)
Other income		—			—			45			—			45
Other deductions		—			—			(32	)		—			(32	)
Interest income		62			—			46			(90	)		18
Interest expense and related charges		(250	)		(142	)		(876	)		229			(1,039	)
Income (loss) before income taxes and equity earnings of subsidiaries		(217	)		(142	)		135			139			(85	)
Income tax (expense) benefit		75			48			(46	)		(46	)		31
Equity earnings of subsidiaries		62			81			—			(143	)		—
Net income (loss)		(80	)		(13	)		89			(50	)		(54	)
Net income attributable to noncontrolling interests		—			—			(26	)		—			(26	)
Net income (loss) attributable to EFH Corp.	$	(80	)	$	(13	)	$	63		$	(50	)	$	(80	)

F-149

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Nine Months Ended September 30, 2010

(millions of dollars)

	Parent/ Issuer			Guarantors			Non- Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	6,599		$	—		$	6,599
Fuel, purchased power costs and delivery fees		—			—			(3,521	)		—			(3,521	)
Net gain from commodity hedging and trading activities		—			—			2,272			—			2,272
Operating costs		—			—			(623	)		—			(623	)
Depreciation and amortization		—			—			(1,043	)		—			(1,043	)
Selling, general and administrative expenses		(18	)		—			(542	)		—			(560	)
Franchise and revenue-based taxes		—			—			(73	)		—			(73	)
Impairment of goodwill		—			—			(4,100	)		—			(4,100	)
Other income		150			—			108			1,020			1,278
Other deductions		—			—			(24	)		1			(23	)
Interest income		160			76			243			(470	)		9
Interest expense and related charges		(807	)		(436	)		(2,685	)		836			(3,092	)
Income (loss) before income taxes and equity in earnings of subsidiaries		(515	)		(360	)		(3,389	)		1,387			(2,877	)
Income tax (expense) benefit		200			130			(168	)		(498	)		(336	)
Equity in earnings of consolidated subsidiaries		(2,898	)		(3,646	)		—			6,544			—
Equity in earnings of unconsolidated subsidiaries (net of tax)		240			240			—			(240	)		240
Net income (loss)		(2,973	)		(3,636	)		(3,557	)		7,193			(2,973	)
Net income attributable to noncontrolling interests		—			—			—			—			—
Net income (loss) attributable to EFH Corp.	$	(2,973	)	$	(3,636	)	$	(3,557	)	$	7,193		$	(2,973	)

F-150

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income

For the Nine Months Ended September 30, 2009

(millions of dollars)

	Parent/ Issuer			Guarantors			Non- Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	7,366		$	—		$	7,366
Fuel, purchased power costs and delivery fees		—			—			(2,171	)		—			(2,171	)
Net gain from commodity hedging and trading activities		—			—			1,003			—			1,003
Operating costs		—			—			(1,171	)		—			(1,171	)
Depreciation and amortization		—			—			(1,286	)		—			(1,286	)
Selling, general and administrative expenses		(92	)		—			(700	)		—			(792	)
Franchise and revenue-based taxes		—			(1	)		(258	)		—			(259	)
Impairment of goodwill		—			—			(90	)		—			(90	)
Other income		2			—			69			—			71
Other deductions		(3	)		—			(47	)		—			(50	)
Interest income		173			—			103			(246	)		30
Interest expense and related charges		(727	)		(423	)		(1,647	)		661			(2,136	)
Income (loss) before income taxes and equity earnings of subsidiaries		(647	)		(424	)		1,171			415			515
Income tax (expense) benefit		213			141			(468	)		(140	)		(254	)
Equity earnings of subsidiaries		641			710			—			(1,351	)		—
Net income		207			427			703			(1,076	)		261
Net income attributable to noncontrolling interests		—			—			(54	)		—			(54	)
Net income attributable to EFH Corp.	$	207		$	427		$	649		$	(1,076	)	$	207

F-151

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Nine Months Ended September 30, 2010

(millions of dollars)

	Parent/ Issuer			Guarantors			Non- Guarantors			Eliminations			Consolidated
Cash provided by operating activities	$	3		$	88		$	723		$	152		$	966
Cash flows — financing activities:
Issuances of long-term borrowings		500			—			—			—			500
Repayments/repurchases of long-term borrowings		(96	)		(3	)		(249	)		(654	)		(1,002	)
Net short-term borrowings under accounts receivable sales program		—			—			228			—			228
Change in other short-term borrowings		—			—			(873	)		—			(873	)
Capital contribution from parent		—			440			—			(440	)		—
Contributions from noncontrolling interests		—			—			24			—			24
Cash dividends paid		—			(2	)		—			2			—
Change in notes/advances — affiliates		(804	)		34			761			(18	)		(27	)
Other, net		(28	)		(30	)		41			—			(17	)
Cash provided by (used in) financing activities		(428	)		439			(68	)		(1,110	)		(1,167	)
Cash flows — investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(793	)		—			(793	)
Capital contribution to subsidiary		(440	)		—			—			440			—
Investment in affiliate debt		—			(500	)		—			500			—
Investment redeemed from derivative counterparty		400			—			—			—			400
Proceeds from sale of assets		—			—			141			—			141
Proceeds from sale of environmental allowances and credits		—			—			7			—			7
Purchases of environmental allowances and credits		—			—			(13	)		—			(13	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			937			—			937
Investments in nuclear decommissioning trust fund securities		—			—			(949	)		—			(949	)
Change in advances — affiliates		(2	)		(16	)		—			18			—
Other, net		(1	)		—			(36	)		—			(37	)
Cash provided by (used in) investing activities		(43	)		(516	)		(706	)		958			(307	)
Net change in cash and cash equivalents		(468	)		11			(51	)		—			(508	)
Effects of deconsolidation of Oncor Holdings		(29	)		—			—			—			(29	)
Cash and cash equivalents — beginning balance		1,059			—			130			—			1,189
Cash and cash equivalents — ending balance	$	562		$	11		$	79		$	—		$	652

F-152

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Nine Months Ended September 30, 2009

(millions of dollars)

	Parent/ Issuer			Guarantors			Non- Guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(43	)	$	113		$	1,907		$	(234	)	$	1,743
Cash flows — financing activities:
Issuances of long-term borrowings		—			—			522			—			522
Retirements of long-term borrowings		—			(3	)		(294	)		—			(297	)
Change in short-term borrowings		—			—			200			—			200
Contributions from noncontrolling interests		—			—			42			—			42
Distributions paid to noncontrolling interests		—			—			(32	)		—			(32	)
Cash dividends paid		—			(117	)		(117	)		234			—
Change in advances — affiliates		289			7			—			(296	)		—
Other, net		20			—			(35	)		—			(15	)
Cash provided by (used in) financing activities		309			(113	)		286			(62	)		420
Cash flows — investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(2,004	)		—			(2,004	)
Redemption of investment held in money market fund		—			—			142			—			142
Investment posted with derivative counterparty		(400	)		—			—			—			(400	)
Net proceeds from sale of assets		—			—			41			—			41
Reduction of letter of credit facility posted with trustee		—			—			115			—			115
Proceeds from sale of environmental allowances and credits		—			—			22			—			22
Purchases of environmental allowances and credits		—			—			(23	)		—			(23	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			2,972			—			2,972
Investments in nuclear decommissioning trust fund securities		—			—			(2,983	)		—			(2,983	)
Change in advances — affiliates		—			—			(296	)		296			—
Other, net		—			—			(9	)		—			(9	)
Cash used in investing activities		(400	)		—			(2,023	)		296			(2,127	)
Net change in cash and cash equivalents		(134	)		—			170			—			36
Cash and cash equivalents — beginning balance		1,075			—			614			—			1,689
Cash and cash equivalents — ending balance	$	941		$	—		$	784		$	—		$	1,725

F-153

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

As of September 30, 2010

(millions of dollars)

	Parent/ Issuer			Guarantors			Non- Guarantors			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	562		$	11		$	79		$	—		$	652
Restricted cash		—			—			31			—			31
Advances to affiliates		—			—			242			(242	)		—
Trade accounts receivable — net		26			177			1,244			(191	)		1,256
Income taxes receivable		376			—			6			(382	)		—
Notes receivable from affiliates		924			—			1,690			(2,614	)		—
Inventories		—			—			388			—			388
Commodity and other derivative contractual assets		137			—			3,383			—			3,520
Accumulated deferred income taxes		10			2			48			—			60
Margin deposits related to commodity positions		—			—			196			—			196
Other current assets		1			—			65			—			66
Total current assets		2,036			190			7,372			(3,429	)		6,169
Restricted cash		—			—			1,135			—			1,135
Receivables from unconsolidated subsidiary		1,270			—			—			—			1,270
Investments in unconsolidated subsidiaries		2,339			104			—			3,082			5,525
Other investments		311			2,692			599			(2,935	)		667
Property, plant and equipment — net		—			—			20,530			—			20,530
Notes receivable from affiliates		12			—			1,609			(1,621	)		—
Goodwill		—			—			6,152			—			6,152
Intangible assets — net		—			—			2,466			—			2,466
Commodity and other derivative contractual assets		—			—			2,553			—			2,553
Accumulated deferred income taxes		326			—			—			(326	)		—
Unamortized debt issuance costs and other noncurrent assets		101			56			578			(88	)		647
Total assets	$	6,395		$	3,042		$	42,994		$	(5,317	)	$	47,114
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	—		$	308		$	—		$	308
Advances from affiliates		239			3			—			(242	)		—
Long-term debt due currently		—			8			244			—			252
Trade accounts payable		1			—			646			—			647
Payables to affiliates/unconsolidated subsidiary		1,691			38			1,105			(2,555	)		279
Commodity and other derivative contractual liabilities		166			—			2,899			—			3,065
Margin deposits related to commodity positions		—			—			693			—			693
Accrued interest		302			97			505			(253	)		651
Other current liabilities		3			32			431			(86	)		380
Total current liabilities		2,402			178			6,831			(3,136	)		6,275
Accumulated deferred income taxes		—			205			5,658			(546	)		5,317
Commodity and other derivative contractual liabilities		—			—			1,422			—			1,422
Notes or other liabilities due affiliates/unconsolidated subsidiary		1,282			—			711			(1,621	)		372
Long-term debt, less amounts due currently		7,115			4,079			29,679			(5,704	)		35,169
Other noncurrent liabilities and deferred credits		1,735			13			2,879			—			4,627
Total liabilities		12,534			4,475			47,180			(11,007	)		53,182
EFH Corp. shareholders’ equity		(6,139	)		(1,433	)		(4,265	)		5,698			(6,139	)
Noncontrolling interests in subsidiaries		—			—			79			(8	)		71
Total equity		(6,139	)		(1,433	)		(4,186	)		5,690			(6,068	)
Total liabilities and equity	$	6,395		$	3,042		$	42,994		$	(5,317	)	$	47,114

F-154

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

As of December 31, 2009

(millions of dollars)

	Parent/ Issuer			Guarantors			Non- Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	1,059		$	—		$	130	$	—		$	1,189
Investment posted with counterparty		425			—			—		—			425
Restricted cash		—			—			48		—			48
Advances to affiliates		471			5			—		(476	)		—
Trade accounts receivable — net		8			2			1,253		(3	)		1,260
Income taxes receivable		23			2			—		(25	)		—
Accounts receivable from affiliates		—			—			22		(22	)		—
Notes receivable from affiliates		114			—			1,469		(1,583	)		—
Inventories		—			—			485		—			485
Commodity and other derivative contractual assets		52			—			2,339		—			2,391
Accumulated deferred income taxes		—			3			11		(9	)		5
Margin deposits related to commodity positions		—			—			187		—			187
Other current assets		2			—			134		—			136
Total current assets		2,154			12			6,078		(2,118	)		6,126
Restricted cash		—			—			1,149		—			1,149
Investments in unconsolidated subsidiaries		—			—			44		—			44
Other investments		4,586			3,634			638		(8,152	)		706
Property, plant and equipment — net		—			—			30,108		—			30,108
Notes receivable from affiliates		12			—			2,236		(2,248	)		—
Goodwill		—			—			14,316		—			14,316
Intangible assets — net		—			—			2,876		—			2,876
Regulatory assets — net		—			—			1,959		—			1,959
Commodity and other derivative contractual assets		—			—			1,533		—			1,533
Accumulated deferred income taxes		647			111			—		(758	)		—
Unamortized debt issuance costs and other noncurrent assets		108			99			733		(95	)		845
Total assets	$	7,507		$	3,856		$	61,670	$	(13,371	)	$	59,662
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	—		$	1,569	$	—		$	1,569
Advances from affiliates		—			—			476		(476	)		—
Long-term debt due currently		—			8			409		—			417
Trade accounts payable		4			—			892		—			896
Accounts payable to affiliates		16			6			—		(22	)		—
Notes payable to affiliates		1,406			27			150		(1,583	)		—
Commodity and other derivative contractual liabilities		82			—			2,310		—			2,392
Margin deposits related to commodity positions		—			—			520		—			520
Accumulated deferred income taxes		9			—			—		(9	)		—
Accrued interest		119			93			408		(94	)		526
Other current liabilities		7			—			761		(24	)		744
Total current liabilities		1,643			134			7,495		(2,208	)		7,064
Accumulated deferred income taxes		—			—			6,764		(633	)		6,131
Investment tax credits		—			—			37		—			37
Commodity and other derivative contractual liabilities		—			—			1,060		—			1,060
Notes or other liabilities due affiliates		2,019			—			229		(2,248	)		—
Long-term debt, less amounts due currently		6,626			4,975			34,740		(4,901	)		41,440
Other noncurrent liabilities and deferred credits		466			3			5,297		—			5,766
Total liabilities		10,754			5,112			55,622		(9,990	)		61,498
EFH Corp. shareholders’ equity		(3,247	)		(1,256	)		4,637		(3,381	)		(3,247	)
Noncontrolling interests in subsidiaries		—			—			1,411		—			1,411
Total equity		(3,247	)		(1,256	)		6,048		(3,381	)		(1,836	)
Total liabilities and equity	$	7,507		$	3,856		$	61,670	$	(13,371	)	$	59,662

F-155

GLOSSARY

When the following terms and abbreviations appear in the text of these financial statements, they have the meanings indicated below.

2008 Audited Financial Statements Oncor Holdings’ audited financial statements for the year ended December 31, 2008

Capgemini Capgemini Energy LP, a provider of business process support services to Oncor

EBITDA Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization

EFH Corp. Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include Oncor and TCEH.

ERCOT Electric Reliability Council of Texas, the independent system operator and the regional coordinator of the various electricity systems within Texas

ERISA Employee Retirement Income Security Act of 1974, as amended

FASB Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting

FERC US Federal Energy Regulatory Commission

GAAP generally accepted accounting principles

Intermediate Holding Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.

Investment LLC Refers to Oncor Management Investment LLC, a limited liability company and noncontrolling interest owner of Oncor, whose managing member is Oncor and whose Class B Interests are owned by officers, directors and key employees of Oncor.

IRS US Internal Revenue Service

kWh kilowatt-hours

LIBOR London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market.

Limited Liability Company

Agreement The Second Amended and Restated Limited Liability Company Agreement of Oncor, dated as of November 5, 2008, by and among Oncor Holdings, Texas Transmission and Investment LLC, as amended.

Luminant Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.

Merger The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007.

F-156

Merger Agreement Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.

Oncor Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings, and/or its wholly-owned consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context.

Oncor Holdings Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of Intermediate Holding and the direct majority owner of Oncor.

Oncor Ring-Fenced Entities Refers to Oncor Holdings and its direct and indirect subsidiaries

OPEB other postretirement employee benefits

PUCT Public Utility Commission of Texas

PURA Texas Public Utility Regulatory Act

Purchase accounting The purchase method of accounting for a business combination as prescribed by GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs, are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.

REP retail electric provider

SARs Stock Appreciation Rights

SARs Plan Refers to the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan

Sponsor Group Collectively, the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P. (KKR), 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 Energy Future Competitive Holdings Company and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context.

Texas Holdings Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.

Texas Holdings Group Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities.

Texas Transmission Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of EFH Corp.’s subsidiaries or any member of the Sponsor Group.

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.

F-157

US United States of America

This prospectus occasionally makes references to Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or any other affiliate.

F-158

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Member of

Oncor Electric Delivery Holdings Company LLC

Dallas, Texas

We have audited the accompanying consolidated balance sheets of Oncor Electric Delivery Holdings Company LLC and subsidiaries (“Oncor Holdings” or the “Successor”) as of December 31, 2009 and 2008 (Successor balance sheets), and the related statements of consolidated income (loss), comprehensive income (loss), cash flows, and membership interests for the years ended December 31, 2009 and 2008 (Successor operations), and the period from October 11, 2007 through December 31, 2007 (Successor operations). We have also audited the accompanying statements of consolidated income (loss), comprehensive income (loss), cash flows, and shareholder’s equity of Oncor Electric Delivery Company LLC (the “Predecessor”) for the period from January 1, 2007 through October 10, 2007 (Predecessor operations). These financial statements are the responsibility of the Oncor Holdings’ management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Oncor Holdings is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Oncor Holdings’ internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, the Successor’s consolidated financial statements referred to above present fairly, in all material respects, the financial position of Oncor Electric Delivery Holdings Company LLC and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for the years ended December 31, 2009 and 2008 and the period from October 11, 2007 through December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. Further, in our opinion, the Predecessor’s consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Oncor Electric Delivery Company LLC for the period from January 1, 2007 through October 10, 2007 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, Oncor Holdings is a wholly-owned subsidiary of Energy Future Holdings Corp., which was merged with Texas Energy Future Merger Sub Corp on October 10, 2007.

/s/    Deloitte & Touche LLP

Dallas, Texas

February 18, 2010

F-159

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR) AND

ONCOR ELECTRIC DELIVERY COMPANY LLC (PREDECESSOR)

STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(millions of dollars)

	Successor								Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007		Period from January 1, 2007 through October 10, 2007
Operating revenues:
Affiliated	$	1,018		$	1,000		$	209	$	823
Nonaffiliated		1,672			1,580			324		1,144
Total operating revenues		2,690			2,580			533		1,967
Operating expenses:
Operation and maintenance		962			852			200		649
Write off of regulatory assets (Note 8)		25			—			—		—
Depreciation and amortization		557			492			96		366
Income taxes		145			191			25		150
Taxes other than income taxes		385			391			87		305
Total operating expenses		2,074			1,926			408		1,470
Operating income		616			654			125		497
Other income and deductions:
Impairment of goodwill (Note 3)		—			860			—		—
Other income (Note 20)		49			45			11		3
Other deductions (Note 20)		14			25			8		30
Nonoperating income taxes		28			26			6		9
Interest income		43			45			12		44
Interest expense and related charges (Note 20)		346			316			70		242
Net income (loss)		320			(483	)		64		263
Net (income) loss attributable to noncontrolling interests		(64	)		160			—		—
Net income (loss) attributable to Oncor Holdings	$	256		$	(323	)	$	64	$	263

See Notes to Financial Statements.

F-160

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR) AND

ONCOR ELECTRIC DELIVERY COMPANY LLC (PREDECESSOR)

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(millions of dollars)

	Successor								Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007		Period from January 1,  2007 through October 10, 2007
Net income (loss)	$	320		$	(483	)	$	64	$	263
Other comprehensive income, net of tax effects:
Cash flow hedges:
Net decrease in fair value of derivatives (net of tax benefit of —, $1, — and —)		—			(2	)		—		—
Derivative value net losses related to hedged transactions recognized during the period in net income (net of tax expense of $—in all periods)		—			—			—		1
Comprehensive income (loss)		320			(485	)		64		264
Comprehensive (income) loss attributable to noncontrolling interests		(64	)		160			—		—
Comprehensive income (loss) attributable to Oncor Holdings	$	256		$	(325	)	$	64	$	264

See Notes to Financial Statements.

F-161

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR) AND

ONCOR ELECTRIC DELIVERY COMPANY LLC (PREDECESSOR)

STATEMENTS OF CONSOLIDATED CASH FLOWS

(millions of dollars)

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Cash flows — operating activities:
Net income (loss)	$	320		$	(483	)	$	64		$	263
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		522			451			95			366
Write off of regulatory assets (Note 8)		25			—			—			—
Deferred income taxes — net		78			159			71			21
Amortization of investment tax credits		(5	)		(5	)		(1	)		(4	)
Reversal of reserve recorded in purchase accounting (Note 13)		(10	)		—			—			—
Impairment of goodwill (Note 3)		—			860			—			—
Bad debt expense		(3	)		1			(2	)		2
Stock-based incentive compensation expense		—			—			—			3
Other, net		2			5			3			1
Changes in operating assets and liabilities:
Accounts receivable — trade (including affiliates)		(29	)		(1	)		39			(47	)
Impact of accounts receivable sales program (Note 9)		—			—			(113	)		27
Inventories		(29	)		(12	)		6			19
Accounts payable — trade (including affiliates)		7			6			(3	)		8
Deferred advanced metering system revenues (Note 8)		57			—			—			—
Other — assets		(40	)		(141	)		(32	)		(24	)
Other — liabilities		55			(11	)		(62	)		47
Cash provided by operating activities		950			829			65			682
Cash flows — financing activities:
Issuance of long-term debt		—			1,500			—			800
Repayments of long-term debt		(104	)		(99	)		(832	)		(264	)
Net increase (decrease) in short-term borrowings		279			(943	)		895			(288	)
Proceeds from sale of noncontrolling interests, net of transaction costs (Note 14)		—			1,253			—			—
Distribution to parent of equity sale net proceeds		—			(1,253	)		—			—
Distributions/dividends to parent		(216	)		(330	)		—			(326	)
Distributions to noncontrolling interests		(56	)		—			—			—
Net decrease in advances from parent		—			—			—			(24	)
Decrease in income tax-related note receivable from TCEH		35			34			9			24
Excess tax benefit on stock-based incentive compensation		—			10			15			—
Debt discount, financing and reacquisition expenses — net		(3	)		(18	)		(1	)		(10	)
Cash provided by (used in) financing activities		(65	)		154			86			(88	)
Cash flows — investing activities:
Capital expenditures		(998	)		(919	)		(162	)		(580	)
Cash settlements related to outsourcing contract termination (Note 16)		—			20			—			—
Other		16			20			16			2
Cash used in investing activities		(982	)		(879	)		(146	)		(578	)
Net change in cash and cash equivalents		(97	)		104			5			16

F-162

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR) AND

ONCOR ELECTRIC DELIVERY COMPANY LLC (PREDECESSOR)

STATEMENTS OF CONSOLIDATED CASH FLOWS (Cont’d)

(millions of dollars)

	Successor						Predecessor
	Year Ended December 31, 2009		Year Ended December 31, 2008		Period from October 11, 2007 through December 31, 2007		Period from January 1, 2007 through October 10, 2007
Cash and cash equivalents — beginning balance		126		22		17		1
Cash and cash equivalents — ending balance	$	29	$	126	$	22	$	17

See Notes to Financial Statements.

F-163

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR)

CONSOLIDATED BALANCE SHEETS

(millions of dollars)

	Successor
	December 31, 2009		December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	29	$	126
Restricted cash (Note 15)		47		51
Trade accounts receivable from nonaffiliates — net (Note 9)		243		217
Trade accounts and other receivables from affiliates		188		182
Income taxes receivable from EFH Corp. (Note 19)		—		22
Materials and supplies inventories — at average cost		92		63
Accumulated deferred income taxes (Note 7)		10		54
Prepayments		76		75
Other current assets		8		9
Total current assets		693		799
Restricted cash (Note 15)		14		16
Investments and other property (Note 15)		72		72
Property, plant and equipment — net (Note 20)		9,174		8,606
Goodwill (Note 20)		4,064		4,064
Note receivable due from TCEH (Note 19)		217		254
Regulatory assets — net (Note 8)		1,959		1,892
Other noncurrent assets		51		60
Total assets	$	16,244	$	15,763
LIABILITIES AND MEMBERSHIP INTERESTS
Current liabilities:
Short-term borrowings (Note 10)	$	616	$	337
Long-term debt due currently (Note 11)		108		103
Trade accounts payable		129		124
Income taxes payable to EFH Corp. (Note 19)		5		—
Accrued taxes other than income taxes		137		141
Accrued interest		104		103
Other current liabilities		106		99
Total current liabilities		1,205		907
Accumulated deferred income taxes (Notes 1 and 7)		1,369		1,333
Investment tax credits		37		42
Long-term debt, less amounts due currently (Note 11)		4,996		5,101
Other noncurrent liabilities and deferred credits (Note 20)		1,879		1,720
Total liabilities		9,486		9,103
Commitments and contingencies (Note 12)
Membership interests (Note 13):
Oncor Holdings membership interest		5,395		5,305
Noncontrolling interests in subsidiary		1,363		1,355
Total membership interests		6,758		6,660
Total liabilities and membership interests	$	16,244	$	15,763

See Notes to Financial Statements.

F-164

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR)

STATEMENTS OF CONSOLIDATED MEMBERSHIP INTERESTS

(millions of dollars)

	Successor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007
Capital account:
Balance at beginning of period (a)	$	5,307		$	7,643		$	7,539
Net income (loss) attributable to Oncor Holdings		256			(323	)		64
Distributions paid to parent		(216	)		(1,583	)		—
Capital contributions (b)		50			—			—
Effect of sale of noncontrolling interests (Notes 13 and 14)		—			(406	)		—
Distribution of investment in Oncor Communications Holding Company LLC to parent		—			(24	)		—
Investment by Texas Holdings		—			—			12
Settlement of incentive compensation plans		—			—			28
Balance at end of period		5,397			5,307			7,643
Accumulated other comprehensive income (loss), net of tax effects:
Balance at beginning of period		(2	)		—			—
Net effects of cash flow hedges		—			(2	)		—
Balance at end of period		(2	)		(2	)		—
Oncor Holdings membership interest at end of period		5,395			5,305			7,643
Noncontrolling interests in subsidiary (Note 14):
Balance at beginning of period		1,355			—			—
Net income (loss) attributable to noncontrolling interests		64			(160	)		—
Distributions to noncontrolling interests		(56	)		(2	)		—
Investment		—			1,253			—
Effect of sale of noncontrolling interests (Note 14)		—			265			—
Other		—			(1	)		—
Noncontrolling interests in subsidiary at end of period		1,363			1,355			—
Total membership interests at end of period	$	6,758		$	6,660		$	7,643

(a) The beginning equity balance for the period from October 11, 2007 through December 31, 2007 reflects the application of push-down accounting as a result of the Merger.

(b) Reflects noncash settlement of certain income taxes payable arising as a result of the sale of noncontrolling interests in Oncor.

See Notes to Financial Statements.

F-165

ONCOR ELECTRIC DELIVERY COMPANY LLC (PREDECESSOR)

STATEMENT OF CONSOLIDATED SHAREHOLDER’S EQUITY

(millions of dollars)

	Predecessor
	Period from January 1, 2007 through October 10, 2007
Common stock without par value (number of authorized shares — 100,000,000):
Balance at beginning of period	$	1,986
Effects of stock-based incentive compensation plans (Note 13)		18
Balance at end of period (number of shares outstanding October 10, 2007 — 0)		2,004
Retained earnings:
Balance at beginning of period		1,008
Net income		263
Dividends to parent		(326	)
Effect of adoption of accounting guidance related to uncertain tax positions (Note 6)		(9	)
Other		1
Balance at end of period		937
Accumulated other comprehensive income (loss), net of tax effects:
Balance at beginning of period		(19	)
Net effects of cash flow hedges		1
Balance at end of period		(18	)
Total shareholder’s equity at end of period	$	2,923

See Notes to Financial Statements.

F-166

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR) AND

ONCOR ELECTRIC DELIVERY COMPANY LLC (PREDECESSOR)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SIGNIFICANT ACCOUNTING POLICIES

Description of Business

Oncor Holdings is a Dallas, Texas-based holding company whose financial statements reflect almost entirely the operations of its direct, majority (approximately 80%) owned subsidiary, Oncor. Oncor is a regulated electricity transmission and distribution company principally engaged in providing delivery services to REPs, including subsidiaries of TCEH, that sell power in the north-central, eastern and western parts of Texas. Distribution revenues from TCEH represented 38% and 39% of total revenues for the years ended December 31, 2009 and 2008, respectively. Oncor Holdings is a direct, wholly-owned subsidiary of Intermediate Holding, a direct, wholly-owned subsidiary of EFH Corp. With the closing of the Merger on October 10, 2007, EFH Corp. became a subsidiary of Texas Holdings, which is controlled by the Sponsor Group (see Note 2), and Oncor Holdings and Intermediate Holding were formed. See “Glossary” for definition of terms and abbreviations, including the Merger. References in these financial statements to Oncor Holdings are to Oncor Holdings and/or its direct or indirect subsidiaries as apparent in the context. Oncor Holdings’ financial statements reflect almost entirely the operations of Oncor; consequently, there are no separate reportable business segments.

Oncor Holdings’ consolidated financial statements include its indirect, bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC. This financing subsidiary was organized for the limited purpose of issuing specified transition bonds in 2003 and 2004. Oncor Electric Delivery Transition Bond Company LLC issued $1.3 billion principal amount of securitization (transition) bonds to recover generation-related regulatory asset stranded costs and other qualified costs under an order issued by the PUCT in 2002.

Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor Holdings and Oncor. These measures serve to mitigate Oncor’s and Oncor Holdings’ credit exposure to the Texas Holdings Group and to reduce the risk that the assets and liabilities of Oncor or Oncor Holdings would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities. Such measures include, among other things: Oncor’s sale of a 19.75% equity interest to Texas Transmission in November 2008; maintenance of separate books and records for the Oncor Ring-Fenced Entities; the board of directors of Oncor Holdings and Oncor being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities’ providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group, 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. Oncor and Oncor Holdings do not bear any liability for obligations of the Texas Holdings Group (including, but not limited to, debt obligations), and vice versa. Accordingly, Oncor Holdings’ operations are conducted, and its cash flows managed, independently from the Texas Holdings Group.

See Note 14 for discussion of noncontrolling interests sold by Oncor in November 2008.

Basis of Presentation

The consolidated financial statements of Oncor Holdings have been prepared in accordance with US GAAP. The accompanying consolidated statements of income (loss), comprehensive income (loss), cash flows and membership interests/shareholder’s equity present results of operations and cash flows of Oncor Holdings for periods subsequent to the Merger (Successor) and of Oncor for periods preceding the Merger (Predecessor), since Oncor Holdings did not exist prior to the Merger. The consolidated financial statements have been prepared on the same basis as the 2008 Audited Financial Statements. The consolidated financial statements of the Successor reflect the application of purchase accounting in accordance with the provisions of accounting standards related to business combinations. 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. Subsequent events have been evaluated through February 18, 2010, the date these consolidated financial statements were issued.

F-167

Income Taxes

EFH Corp. files a consolidated federal income tax return. Prior to 2007, federal income taxes were allocated to subsidiaries, including Oncor Holdings and Oncor, based on their respective taxable income or loss. Effective with the November 2008 sale of equity interests in Oncor (see Note 14), Oncor became a partnership for US federal income tax purposes, and subsequently EFH Corp.’s share of partnership income is included in its consolidated federal income tax return. In connection with the Merger, Oncor, Oncor Holdings and EFH Corp. entered into a tax sharing agreement (amended in November 2008 to include Texas Transmission and Investment LLC) that is retroactive to January 1, 2007. The tax sharing agreement provides for the calculation of tax liability for each of Oncor Holdings and Oncor substantially as if these entities file their own income tax returns and requires tax payments to their members determined on that basis (without duplication for any income taxes paid by a subsidiary of Oncor Holdings). Deferred income taxes are provided for temporary differences between the book and tax bases of assets and liabilities of Oncor Holdings, which primarily relate to the difference between the book and tax basis of the investment in Oncor.

Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, are determined in accordance with the provisions of accounting guidance for income taxes and for uncertainty in income taxes. See Note 7 for additional detail.

Use of Estimates

Preparation of Oncor Holdings’ 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 was 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, a portion of which was assigned to Oncor Holdings. See Note 2 for details regarding the effect of purchase accounting.

Derivative Instruments and Mark-to-Market Accounting

Oncor has from time-to-time entered into derivative instruments, referred to as interest rate swaps, to hedge interest rate risk. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, the fair value of each derivative is required to be recognized on the balance sheet as a derivative asset or liability and changes in the fair value recognized in net income, unless criteria for certain exceptions are met. This recognition is referred to as “mark-to-market” accounting.

Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for “hedge accounting,” which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met. A cash flow hedge mitigates the risk associated with the variability of the future cash flows related to an asset or liability (e.g., debt with variable interest rate payments), while a fair value hedge mitigates risk associated with fixed future cash flows (e.g., debt with fixed interest rate payments). In accounting for cash flow hedges, derivative assets and liabilities are recorded on the balance sheet at fair value with an offset to other comprehensive income to the extent the hedges are effective. Amounts remain in accumulated other comprehensive income, unless the underlying transactions become probable of not occurring, and are reclassified into net income as the related transactions (hedged items) settle and affect net income. 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. 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. Hedge ineffectiveness, even if the hedge continues to be assessed as effective, is 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.

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Revenue Recognition

Revenue from delivery services are recorded under the accrual method of accounting. Revenues are recognized when delivery services are provided to customers on the basis of periodic cycle meter readings and include an estimate for revenues earned from the meter reading date to the end of the period with an adjustment for the impact of weather and other factors on unmetered deliveries (unbilled revenue).

Impairment of Goodwill and Other Intangible Assets

Oncor Holdings evaluates goodwill for impairment at least annually. The impairment tests performed are based on determinations of enterprise value using discounted cash flow analyses, comparable company equity values and any relevant transactions indicative of enterprise values. See Note 20 for details of goodwill and other intangible assets and Note 3 for discussion of a goodwill impairment charge recorded in 2008.

In 2009, Oncor Holdings changed the annual test date from October 1 to December 1. Management determined the new annual goodwill test date is preferable because of efficiencies gained by aligning the test with Oncor Holdings’ annual budget and five-year plan processes in the fourth quarter. The change in the annual test date did not delay, accelerate or avoid an impairment charge, and retrospective application of this change in accounting principle did not affect previously reported results.

System of Accounts

The accounting records of Oncor Holdings have been maintained in accordance with the FERC Uniform System of Accounts as adopted by the PUCT.

Defined Benefit Pension Plans and Other Postretirement Employee Benefit (OPEB) Plans

Oncor participates in an EFH Corp. pension plan that offers benefits based on either a traditional defined benefit formula or a cash balance formula and an OPEB plan that offers certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from Oncor. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. See Note 17 for additional information regarding pension and OPEB plans.

Stock-Based Incentive Compensation

Prior to the Merger, EFH Corp. provided discretionary awards payable in its common stock to qualified managerial employees of Oncor under EFH Corp.’s shareholder-approved long-term incentive plans. Oncor Holdings recognized expense for these awards over the vesting period based on the grant-date fair value of those awards. In November 2008, Oncor implemented the SARs Plan for certain management that purchased equity interests in Oncor indirectly by investing in Investment LLC. SARs have been awarded under the SARs Plan and are being accounted for based upon the provisions of guidance for share-based payment. See Note 18 for information regarding stock-based compensation, including SARs granted to certain members of Oncor’s board of directors.

Fair Value of Nonderivative Financial Instruments

The carrying amounts for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value due to the short maturity of such instruments. The fair values of other financial instruments, for which carrying amounts and fair values have not been presented, are not materially different than their related carrying amounts.

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Franchise Taxes

Franchise taxes are assessed to Oncor by local governmental bodies, based on kWh delivered and are the principal component of “taxes other than income taxes” as reported in the income statement. Franchise taxes are not a “pass through” item. Rates charged to customers by Oncor are intended to recover the franchise taxes, but Oncor is not acting as an agent to collect the taxes from customers.

Cash and Cash Equivalents

For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents. See Note 15 for details regarding restricted cash.

Property, Plant and Equipment

Properties are stated at original cost. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead and an allowance for funds used during construction.

Depreciation of property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties based on depreciation rates approved by the PUCT. Depreciation rates include plant removal costs as a component of depreciation expense, consistent with regulatory treatment. As is common in the industry, depreciation expense is recorded using composite depreciation rates that reflect blended estimates of the lives of major asset groups as compared to depreciation expense calculated on a component asset-by-asset basis.

In accordance with the PUCT’s August 2009 order in Oncor’s rate review, the remaining net book value and anticipated removal cost of existing meters that are being replaced by advanced meters is being charged (amortized) to expense over an 11-year cost recovery period.

Allowance For Funds Used During Construction (AFUDC)

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. AFUDC is capitalized on all projects involving construction periods lasting greater than thirty days. The equity portion of capitalized AFUDC is accounted for as other income. There was no equity AFUDC for the periods presented. See Note 20 for detail of amounts charged to interest expense.

Regulatory Assets and Liabilities

The financial statements of Oncor Holdings reflect regulatory assets and liabilities under cost-based rate regulation in accordance with accounting standards related to the effect of certain types of regulation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 8 for details of regulatory assets and liabilities.

Sale of Noncontrolling Interests

See Note 14 for discussion of accounting for the sale of noncontrolling interests by Oncor.

Changes in Accounting Standards

In June 2009, the FASB issued “The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles,” which establishes the FASB Accounting Standards Codification™ (Codification) as the source of authoritative US GAAP recognized by the FASB to be applied to nongovernmental entities. The Codification was effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of the Codification did not affect reported results of operations, financial condition or cash flows.

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In May 2009, the FASB issued new guidance related to subsequent events that requires disclosure of the date through which Oncor Holdings has evaluated subsequent events related to the financial statements being issued and the basis for that date. The adoption of this guidance as of April 1, 2009 did not affect reported results of operations, financial condition or cash flows, and the required disclosure is provided above in “Basis of Presentation.”

2. FINANCIAL STATEMENT EFFECTS OF THE MERGER

EFH Corp. accounted for the Merger under purchase accounting in accordance with the provisions of accounting standards related to business combinations, 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 the Merger date. As a result of cost-based regulatory rate-setting processes, the book value of the majority of Oncor’s assets and liabilities effectively represents fair value, and no adjustments to the carrying value of 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 purchase price was allocated to TCEH and Oncor. The purchase price amount assigned to Oncor was based on the relative enterprise value of the business on the closing date of the Merger and resulted in an excess of purchase price over fair value of assets and liabilities of $4.9 billion, which was recorded as goodwill. See Note 20 for disclosures related to goodwill and Note 3 regarding an impairment charge recorded in the fourth quarter of 2008.

The following table summarizes the final purchase price allocation to the estimated fair values of the assets acquired and liabilities assumed (billions of dollars):

Purchase price assigned to Oncor		$	7.6
Property, plant and equipment	7.9
Regulatory assets — net	1.3
Other assets	1.3
Total assets acquired	10.5
Short-term borrowings and long-term debt	5.1
Deferred income tax liabilities	1.3
Other liabilities	1.4
Total liabilities assumed	7.8
Net identifiable assets acquired			2.7
Goodwill		$	4.9

As part of purchase accounting, the carrying value of certain generation-related regulatory assets securitized by transition bonds, which have been reviewed and approved by the PUCT for recovery but without earning a rate of return, was reduced by $213 million. This amount will be accreted to other income over the recovery period remaining as of the closing date of the Merger (approximately nine years). The related securitization (transition) bonds were also fair valued and the resulting discount of $12 million will be amortized to interest expense over the life of the bonds remaining as of the closing date of the Merger (approximately nine years).

The final purchase price allocation includes $16 million in liabilities recorded in connection with the notice of termination of outsourcing arrangements with Capgemini under the change of control provisions of such arrangements (also see Note 16). Oncor incurred $4 million of these exit liabilities during the year ended December 31, 2009. In December 2009, Oncor recorded a $10 million reversal of a portion of these exit liabilities due primarily to a shorter than expected outsourcing services transition period, and this reversal is reflected in other income (see Note 19). The remaining accrual totaling $2 million is expected to be settled in 2010.

3. GOODWILL IMPAIRMENT

The 2009 annual goodwill impairment testing performed as of October 1 and December 1, 2009 in accordance with accounting guidance for a change in annual impairment testing dates resulted in no impairment (see discussion in Note 1 regarding change in the annual test date from October 1 to December 1). The testing determined that Oncor Holdings’ estimated fair value (enterprise value) exceeded its carrying value by approximately 10%, resulting in no additional testing being required and no impairment. Key assumptions in the valuation include discount rates, growth of the rate base and return on equity allowed by the regulatory authority.

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In the fourth quarter of 2008, Oncor Holdings recorded a goodwill impairment charge totaling $860 million, which is not deductible for income tax-related purposes.

Although the annual goodwill impairment test date set by management was October 1, management determined that in consideration of the continuing deterioration of securities values during the fourth quarter of 2008, an impairment testing trigger occurred subsequent to that test date; consequently, the impairment charge was based on estimated fair values at December 31, 2008. The fair value calculation was completed in the first quarter of 2009 with no additional impairment charge.

The impairment determination involved significant assumptions and judgments in estimating enterprise values and the fair values of assets and liabilities. The impairment primarily arose from the dislocation in the capital markets that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies.

The calculations supporting the impairment determination utilized models that took into consideration multiple inputs, including debt yields, equity prices of comparable companies and other inputs. These models were generally used in developing long-term forward discount rates for determining enterprise value and fair values of certain individual assets and liabilities. The fair value measurements resulting from such models are classified as Level 3 non-recurring fair value measurements consistent with accounting standards related to the determination of fair value.

4. STIPULATION APPROVED BY THE PUCT

Oncor and Texas Holdings agreed to the terms of a stipulation, which was conditional upon completion of the Merger, with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. In February 2008, the PUCT entered an order approving the stipulation. The PUCT issued a final order on rehearing in April 2008 that has been appealed to the 200th District Court of Travis County, Texas. The parties to the appeal have agreed to a schedule that would result in a hearing in June 2010.

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

• Oncor provided a one-time $72 million refund to its REP customers in the September 2008 billing cycle. The refund was in the form of a credit on distribution fee billings. The liability for the refund was recorded as part of purchase accounting.

• Consistent with the 2006 cities rate settlement (see Note 5), Oncor filed a system-wide rate case in June 2008 based on a test-year ended December 31, 2007. In August 2009, the PUCT issued a final order on this rate case. See Note 8.

• Oncor agreed not to request recovery of approximately $56 million of regulatory assets related to self-insurance reserve costs and 2002 restructuring expenses. These regulatory assets were eliminated as part of purchase accounting.

• The dividends paid by Oncor will be limited through December 31, 2012, to an amount not to exceed Oncor’s net income (determined in accordance with GAAP, subject to certain defined adjustments) for the period beginning October 11, 2007 and ending December 31, 2012, and are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.

• Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions.

• Oncor committed to an additional $100 million in spending over the five-year period ending December 31, 2012 on demand-side management or other energy efficiency initiatives. These additional expenditures will not be recoverable in rates, and this amount was recorded as a regulatory liability as part of purchase accounting and consistent with accounting standards related to the effect of certain types of regulation.

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• If Oncor’s credit rating is below investment grade with two or more rating agencies, TCEH will post a letter of credit in an amount of $170 million to secure TXU Energy’s payment obligations to Oncor.

• Oncor agreed not to request recovery of the $4.9 billion of goodwill resulting from purchase accounting or any future impairment of the goodwill in its rates.

5. CITIES RATE SETTLEMENT IN 2006

In January 2006, Oncor agreed with a steering committee representing 108 cities in Texas (Cities) to defer the filing of a system-wide rate case with the PUCT to no later than July 1, 2008 (based on a test year ending December 31, 2007). Oncor filed the rate case with the PUCT in June 2008, and the PUCT issued a final order on the case in 2009. Oncor extended the benefits of the agreement to 292 nonlitigant cities. The agreements provided that Oncor would make payments to participating cities totaling approximately $70 million, including incremental franchise taxes.

This amount was recognized in earnings over the period from May 2006 through June 2008. Amounts recognized totaled $11 million in 2009, $23 million in 2008, $8 million for the period October 11, 2007 through December 31, 2007 and $25 million for the period January 1, 2007 through October 10, 2007, of which $2 million, $13 million, $6 million and $20 million, respectively, is reported in other deductions (see Note 20), and the remainder as taxes other than income taxes. Amounts recognized in 2009 represented extension of benefits per the agreement as a result of the timing of completion of the rate case.

6. ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES

Effective January 1, 2007, EFH Corp. and its subsidiaries adopted accounting guidance related to uncertain tax positions. This guidance 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. Oncor Holdings applied updated guidance to determine if each tax position was effectively settled for the purpose of recognizing previously uncertain tax positions. Oncor Holdings completed its review and assessment of uncertain tax positions and in 2007 recorded a net charge to retained earnings and an increase to noncurrent liabilities of $9 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 EFH Corp. and its subsidiaries’ income tax returns for the years ending prior to January 1, 2003 are complete, but the tax years 1997 through 2002 remain in appeals with the IRS. In 2008, EFH Corp. was notified of the commencement of an IRS audit of tax years 2003 to 2006. The audit is expected to require two years to complete. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginning after 2002. Prior to the 2007 Merger, Oncor was a member of EFH Corp.’s consolidated group federal income tax returns.

Oncor Holdings classifies interest and penalties expense related to uncertain tax positions as current income tax expense. Amounts recorded related to interest and penalties totaled a benefit of $5 million in the year ended December 31, 2009 and expenses of $6 million (including $2 million recorded as goodwill) in the year ended December 31, 2008, $2 million for the period October 11, 2007 through December 31, 2007 and $3 million for the period January 1, 2007 through October 10, 2007 (all amounts after tax).

Noncurrent liabilities included a total of $20 million and $22 million in accrued interest at December 31, 2009 and 2008, respectively. Effective in 2009, the federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferred income taxes. Such amounts were previously reported net as a reduction of the liability for uncertain tax positions.

The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in the consolidated balance sheet, during the years ended December 31, 2009 and 2008:

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	2009			2008
Balance at January 1, excluding interest and penalties	$	122		$	111
Additions based on tax positions related to prior years		22			41
Reductions based on tax positions related to prior years		(73	)		(30	)
Additions based on tax positions related to the current year		—			—
Balance at December 31, excluding interest and penalties	$	71		$	122

Of the balance at December 31, 2009, $60 million represents tax positions for which the uncertainty relates to the timing of recognition for tax purposes. The disallowance of such positions would not affect the effective tax rate, but would accelerate the payment of cash under the tax sharing agreement to an earlier period.

With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), should EFH Corp. or Oncor Holdings sustain such positions on income tax returns previously filed, Oncor Holdings’ liabilities recorded would be reduced by $11 million, resulting in increased net income and a favorable impact on the effective tax rate.

Oncor Holdings does not expect the total amount of liabilities recorded related to uncertain tax positions will significantly increase or decrease within the next 12 months.

7. INCOME TAXES

The components of Oncor Holdings’ income tax expense are as follows:

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Reported in operating expenses:
Current:
US federal	$	69		$	37		$	(46	)	$	116
State		17			17			—			12
Deferred:
US federal		67			142			74			26
State		(3	)		—			(2	)		—
Amortization of investment tax credits		(5	)		(5	)		(1	)		(4	)
Total		145			191			25			150
Reported in other income and deductions:
Current:
US federal		13			8			7			8
State		1			1			—			1
Deferred federal		14			17			(1	)		—
Total deferred		28			26			6			9
Total income tax expense	$	173		$	217		$	31		$	159

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

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Income (loss) before income taxes	$	493		$	(266	)	$	95		$	422
Income taxes at the US federal statutory rate of 35%	$	173		$	(93	)	$	33		$	148
Goodwill impairment		—			301			—			—
Amortization of investment tax credits — net of deferred tax effect		(5	)		(5	)		(1	)		(4	)
Amortization (under regulatory accounting) of statutory tax rate changes		(2	)		(3	)		(1	)		(3	)
Texas margin tax, net of federal tax benefit		12			11			(1	)		8
Medicare subsidy		(6	)		(5	)		(2	)		(5	)
Nondeductible losses (gains) on benefit plan investments		(1	)		4			—			(2	)
Other, including audit settlements		2			7			3			17
Income tax expense	$	173		$	217		$	31		$	159
Effective rate		35.1	%		—			32.6	%		37.7	%

Deferred income taxes provided for temporary differences based on tax laws in effect at the December 31, 2009 and 2008 balance sheet dates are as follows:

	Successor
	December 31, 2009							December 31, 2008 (a)
	Total		Current			Noncurrent		Total		Current			Noncurrent
Deferred Income Tax Assets:
Alternative minimum tax credit carryforwards	$	10	$	10		$	—	$	54	$	54		$	—
Total		10		10			—		54		54			—
Deferred Income Tax Liabilities:
Basis difference in Oncor partnership		1,369		—			1,369		1,333		—			1,333
Total		1,369		—			1,369		1,333		—			1,333
Net Deferred Income Tax (Asset) Liability	$	1,359	$	(10	)	$	1,369	$	1,279	$	(54	)	$	1,333

(a) See Note 13.

At December 31, 2009, Oncor Holdings had $10 million of alternative minimum tax (AMT) credit carryforwards available to offset future tax sharing payments. The AMT credit carryforwards have no expiration date.

The component of deferred income tax liabilities referred to as “basis difference in Oncor partnership” arose as a result of the Oncor equity interests sale (see Note 14) at which time Oncor became a partnership for US federal income tax purposes. The amount of this basis difference at the date of the transaction represented Oncor Holdings’ interest (approximately 80%) in the net deferred tax liabilities related to Oncor’s individual operating assets and liabilities. The remaining net deferred tax liabilities associated with Oncor ($321 million at December 31, 2009) that are attributable to the noncontrolling interests have been reclassified as other noncurrent liabilities (see Note 20).

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

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8. REGULATORY ASSETS AND LIABILITIES

Recognition of regulatory assets and liabilities and the amortization periods over which they are expected to be recovered or refunded through rate regulation reflect the decisions of the PUCT. Components of the regulatory assets and liabilities are provided in the table below. Amounts not earning a return through rate regulation are noted. On August 31, 2009, the PUCT issued a final order on Oncor’s rate review filed in June 2008. The rate review included a determination of the recoverability of regulatory assets as of December 31, 2007, including the recoverability period of those assets deemed allowable by the PUCT. The PUCT’s findings included denial of recovery of certain regulatory assets primarily related to business restructuring costs and rate case expenses, which resulted in a $25 million charge ($16 million after-tax) in the third quarter 2009 reported as write off of regulatory assets.

	Remaining Rate Recovery/Amortization Period as of December 31, 2009	Carrying Amount
		December 31, 2009		December 31, 2008
Regulatory assets:
Generation-related regulatory assets securitized by transition bonds (a)	7 years	$	759	$	865
Employee retirement costs	5 years		80
Employee retirement costs to be reviewed (b)(c)	To be determined		41		100
Employee retirement liability (a)(c)(d)	To be determined		768		559
Self-insurance reserve (primarily storm recovery costs) — net	7 years		137		—
Self-insurance reserve to be reviewed (b)(c)	To be determined		106		214
Nuclear decommissioning cost under-recovery (a)(c)(e)	Not applicable		85		127
Securities reacquisition costs (pre-industry restructure)	8 years		62		68
Securities reacquisition costs (post-industry restructure)	Terms of related debt		27		29
Recoverable amounts for/in lieu of deferred income taxes — net	Life of related asset or liability		68		77
Rate case expenses (f)	Largely 3 years		9		10
Rate case expenses to be reviewed (b)(c)	To be determined		1		—
Advanced meter customer education costs	10 years		4		2
Deferred conventional meter depreciation	10 years		14		—
Energy efficiency performance bonus	1 year		9		—
Business restructuring costs (g)	Not applicable		—		20
Total regulatory assets			2,170		2,071
Regulatory liabilities:
Committed spending for demand-side management initiatives (a)	3 years		78		96
Deferred advanced metering system revenues	10 years		57		—
Investment tax credit and protected excess deferred taxes	Various		44		49
Over-collection of securitization (transition) bond revenues (a)	7 years		27		28
Other regulatory liabilities (a)	Various		5		6
Total regulatory liabilities			211		179
Net regulatory asset		$	1,959	$	1,892

(a) Not earning a return in the regulatory rate-setting process.

(b) Costs incurred since the period covered under the last rate review.

(c) Recovery is specifically authorized by statute, subject to reasonableness review by the PUCT.

(d) Represents unfunded liabilities recorded in accordance with pension and OPEB accounting standards.

(e) Offset by an intercompany payable to TCEH. See Note 19.

(f) Rate case expenses totaling $4 million were disallowed by the PUCT and written off in the third quarter of 2009.

(g) All previously recorded business restructuring costs were disallowed by the PUCT and written off in the third quarter of 2009.

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In September 2008, the PUCT approved a settlement for Oncor to recover its estimated future investment for advanced metering deployment. Oncor began billing the advanced metering surcharge in the January 2009 billing month cycle. The surcharge is expected to total $1.023 billion over the 11-year recovery period and includes a cost recovery factor of $2.19 per month per residential retail customer and $2.39 to $5.15 per month for non-residential retail customers. Oncor Holdings accounts for the difference between the surcharge billings for advanced metering facilities and the allowed revenues under the surcharge provisions, which are based on expenditures and an allowed return, as a regulatory asset or liability. Such differences arise principally as a result of timing of expenditures. As indicated in the table above, the regulatory liability at December 31, 2009 totaled $57 million.

See Note 2 for a discussion of effects of purchase accounting on the carrying value of generation-related regulatory assets, Note 4 for discussion of effects on regulatory assets and liabilities of the stipulation approved by the PUCT and Note 19 for additional information regarding nuclear decommissioning cost recovery.

9. TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

Trade Accounts Receivable

	December 31, 2009			December 31, 2008
Gross trade accounts receivable	$	395		$	359
Trade accounts receivable from TCEH		(150	)		(135	)
Allowance for uncollectible accounts		(2	)		(7	)
Trade accounts receivable from nonaffiliates — net	$	243		$	217

Gross trade accounts receivable at December 31, 2009 and 2008 included unbilled revenues of $141 million and $140 million, respectively.

In April 2009, the PUCT finalized a new rule relating to the Certification of Retail Electric Providers. Under the new rule, write-offs of uncollectible amounts owed by REPs are deferred as a regulatory asset. Accordingly, Oncor Holdings recognized a $3 million one-time reversal of bad debt expense in 2009 representing bad debt reserves previously recognized for nonaffiliated REP accounts receivable. Due to the commitments made to the PUCT in connection with the Merger, Oncor may not recover bad debt expense, or certain other costs and expenses, from rate payers in the event of a default or bankruptcy by an affiliate REP.

Sale of Receivables

Prior to the Merger, Oncor participated in an accounts receivable securitization program established by EFH Corp. for certain of its subsidiaries, the activity under which was accounted for as a sale of accounts receivable in accordance with transfers and servicing accounting standards. Under the program, Oncor sold trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp., which sold undivided interests in those 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. Concurrently, 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 the related subordinated note receivable from TXU Receivables Company in the amount of $141 million was canceled. Oncor is no longer a participant in the accounts receivable securitization program.

Under the program, new trade receivables generated by Oncor were 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, reflected seasonal variations in the level of accounts receivable, changes in collection trends as well as other factors such as changes in delivery fees and volumes. TXU Receivables Company issued subordinated notes payable to Oncor for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to Oncor that was funded by the sale of the undivided interests.

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The discount from face amount on the purchase of receivables principally funded program fees paid by TXU Receivables Company to the funding entities. The discount also funded a servicing fee paid by TXU Receivables Company to EFH Corporate Services Company, a direct subsidiary of EFH Corp., but the amounts were immaterial. The program fees, referred to as losses on sale of the receivables under transfers and servicing accounting standards, consisted primarily of interest costs on the underlying financing and totaled $6 million and averaged 6.4% (on an annualized basis) as a percentage of the average funding under the program for the Predecessor period from January 1, 2007 through October 10, 2007. These fees represented essentially all of the net incremental costs of the program to Oncor and were reported in operation and maintenance expenses.

Funding under the program decreased $86 million to zero in 2007 with Oncor’s exit from the program. Funding increases or decreases under the program were 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 related to Oncor in 2007 were as follows:

	Successor (a)		Predecessor
	Period from October 11, 2007 through December 31, 2007		Period from January 1, 2007 through October 10, 2007
Cash collections on accounts receivable	$	—	$	1,082
Face amount of new receivables purchased		—		(1,156	)
Discount from face amount of purchased receivables		—		5
Program fees paid to funding entities		—		(6	)
Increase in subordinated notes payable		—		48
Repurchase of receivables previously sold		113		—
Operating cash flows used by (provided to) Oncor under the program	$	113	$	(27	)

(a) Represents final activities related to Oncor’s exit from the sale of receivables program.

10. BORROWINGS UNDER CREDIT FACILITIES

At December 31, 2009, Oncor had a $2.0 billion secured revolving credit facility, expiring October 10, 2013, to be used for its 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. Amounts borrowed under the facility, once repaid, can be borrowed again by Oncor from time to time. Borrowings are classified as short-term on the balance sheet. 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 current credit facility.

At December 31, 2009, Oncor had outstanding borrowings under the credit facility totaling $616 million with an interest rate of 0.58% at the end of the period. At December 31, 2008, Oncor had outstanding borrowings under the credit facility totaling $337 million with an interest rate of 1.98% at the end of the period. Availability under the credit facility as of December 31, 2009 was $1.262 billion. This availability excludes $122 million of commitments from a subsidiary of Lehman Brothers Holding Inc. (such subsidiary, Lehman) that has filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. Availability under the credit facility as of December 31, 2008 was $1.508 billion, which excluded $155 million of commitments from Lehman.

Under the terms of Oncor’s 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 facility.

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 ratings 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 ratings as of December 31, 2009, its LIBOR-based borrowings, which apply to all outstanding borrowings at December 31, 2009, bear interest at LIBOR plus 0.350%.

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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 as of December 31, 2009, its facility fee is 0.125%. 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.

11. LONG-TERM DEBT

At December 31, 2009 and 2008, long-term debt consisted of the following:

	December 31, 2009			December 31, 2008
Oncor (a):
6.375% Fixed Senior Notes due May 1, 2012	$	700		$	700
5.950% Fixed Senior Notes due September 1, 2013		650			650
6.375% Fixed Senior Notes due January 15, 2015		500			500
6.800% Fixed Senior Notes due September 1, 2018		550			550
7.000% Fixed Debentures due September 1, 2022		800			800
7.000% Fixed Senior Notes due May 1, 2032		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
7.500% Fixed Senior Notes due September 1, 2038		300			300
Unamortized discount		(15	)		(16	)
Total Oncor		4,335			4,334
Oncor Electric Delivery Transition Bond Company LLC (b):
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		13			54
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		130			130
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		145			145
3.520% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2009		—			39
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		197			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		775			879
Unamortized fair value discount related to transition bonds (c)		(6	)		(9	)
Total consolidated (d)		5,104			5,204
Less amount due currently		(108	)		(103	)
Total long-term debt	$	4,996		$	5,101

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(a) Secured with first priority lien as discussed in Note 10.

(b) The transition bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset.

(c) The transition bonds, which secured regulatory assets not earning a return, were fair valued as of October 10, 2007 as a result of purchase accounting.

(d) According to its organizational documents, Oncor Holdings is prohibited from directly incurring indebtedness for borrowed money.

Debt Repayments in 2009

Repayments of long-term debt in 2009 totaled $104 million and represent transition bond principal payments at scheduled maturity dates.

Debt-Related Activity in 2008

In September 2008, Oncor issued and sold senior secured notes with an aggregate principal amount of $1.5 billion consisting of $650 million aggregate principal amount of 5.95% senior secured notes maturing in September 2013, $550 million aggregate principal amount of 6.80% senior secured notes maturing in September 2018 and $300 million aggregate principal amount of 7.50% senior secured notes maturing in September 2038. Oncor used the net proceeds of approximately $1.487 billion from the sale of the notes to repay most of its borrowings under its credit facility as well as for general corporate purposes. The notes are secured by the first priority lien described in Note 10. The notes are secured equally and ratably with all of Oncor’s other secured indebtedness. 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. Oncor may redeem the notes, in whole or in part, at any time, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. The notes also contain customary events of default, including failure to pay principal or interest on the notes when due.

Repayments of long-term debt in 2008 totaled $99 million and represent transition bond principal payments at scheduled maturity dates.

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. After-tax net losses of less than one million will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

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Maturities

Long-term debt and transition bonds maturities are as follows:

Year
2010	$	108
2011		113
2012		819
2013		775
2014		131
Thereafter		3,179
Unamortized fair value discount		(6	)
Unamortized discount		(15	)
Total	$	5,104

Fair Value of Long-Term Debt

The estimated fair value of long-term debt (including current maturities) totaled $5.644 billion and $4.990 billion at December 31, 2009 and 2008, respectively, and the carrying amount totaled $5.104 billion and $5.204 billion, respectively. The fair value is estimated at the lesser of either the call price or the market value as determined by quoted market prices.

12. COMMITMENTS AND CONTINGENCIES

Leases

At December 31, 2009, future minimum lease payments under operating leases (with initial or remaining noncancelable lease terms in excess of one year) were as follows:

Year
2010	$	12
2011		12
2012		10
2013		4
2014		4
Thereafter		7
Total future minimum lease payments	$	49

Rent charged to operation and maintenance expense totaled $11 million and $10 million for the years ended December 31, 2009 and 2008, respectively, $3 million for the period October 11, 2007 through December 31, 2007 and $7 million for the Predecessor period January 1, 2007 through October 10, 2007.

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 4.

Efficiency Spending

Oncor is required to annually invest in programs designed to improve customer electricity demand efficiencies to satisfy its ongoing regulatory requirements. The 2010 requirement is $44 million. Oncor also committed to invest $100 million in these programs in excess of regulatory requirements over the five years ending in 2012. See Note 4.

Guarantees

Oncor has entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions.

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Oncor is the lessee under various operating leases that obligate it to guarantee the residual values of the leased assets. At December 31, 2009, both the aggregate maximum amount of residual values guaranteed and the estimated residual recoveries totaled approximately $6 million. These leased assets consist primarily of vehicles used in distribution activities. The average life of the residual value guarantees under the lease portfolio is approximately two years.

Legal Proceedings

Oncor Holdings is involved in various 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 upon its financial position, results of operations or cash flows.

Labor Contracts

Certain Oncor employees are represented by a labor union and covered by a collective bargaining agreement that will expire in October 2010. In June 2009, a group of approximately 50 employees voted to decertify the labor union as their representative. In December 2009, a group of approximately 350 employees elected to be represented by a labor union. The negotiation of a new labor agreement and the representation of this group of additional employees is not expected to have a material effect on Oncor Holdings’ financial position, results of operations or cash flows.

Environmental Contingencies

Oncor must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. Oncor is in compliance with all current 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:

• changes to existing state or federal regulation by governmental authorities having jurisdiction over control of toxic substances and hazardous and solid wastes, and other environmental matters, and

• the identification of additional sites requiring clean-up or the filing of other complaints in which Oncor Holdings may be asserted to be a potential responsible party.

13. MEMBERSHIP INTERESTS

Successor

Cash Distributions — On February 11, 2010, the board of directors declared a cash distribution of between $34 million and $41 million to be paid to Intermediate Holding on February 19, 2010.

During 2009, Oncor Holdings’ board of directors declared, and Oncor Holdings paid, the following cash distributions to Intermediate Holding:

Declaration Date	Payment Date	Amount Paid
November 12, 2009	November 13, 2009	$        99
August 18, 2009	August 19, 2009	$        59
May 19, 2009	May 20, 2009	$        40
February 18, 2009	March 3, 2009	$        18

During 2008, Oncor Holdings’ board of directors declared, and Oncor Holdings paid, the following cash distributions to Intermediate Holding:

Declaration Date	Payment Date	Amount Paid
November 13, 2008	November 14, 2008	$      117
August 20, 2008	August 21, 2008	$        78
May 14, 2008	May 15, 2008	$        78
February 20, 2008	March 31, 2008	$        57

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The net proceeds of $1.253 billion from Oncor’s sale of equity interests in November 2008 were distributed to Intermediate Holding and ultimately to EFH Corp.

While there are no direct restrictions on Oncor Holdings’ ability to distribute its net income that are currently material, substantially all of Oncor Holdings’ net income is derived from Oncor. The boards of directors of each of Oncor and Oncor Holdings, which are composed of a majority of independent directors, can withhold distributions to the extent the boards determine that it is necessary to retain such amounts to meet expected future requirements of Oncor and/or Oncor Holdings. For the period beginning October 11, 2007 and ending December 31, 2012, distributions paid by Oncor (other than distributions of the proceeds of any issuance of limited liability company units) are limited by the Limited Liability Company Agreement to an amount not to exceed Oncor’s net cumulative income determined in accordance with GAAP, as adjusted by applicable orders of the PUCT. Such adjustments include deducting the $72 million ($46 million after tax) one-time refund to customers in September 2008 and deducting funds spent as part of the $100 million commitment for additional demand-side management or other energy efficiency initiatives (see Note 4) of which $22 million ($14 million after tax) has been spent through December 31, 2009, neither of which impacted net income due to purchase accounting, and removing the effect of the $860 million goodwill impairment charge from fourth quarter 2008 net income available for distribution. The goodwill impairment charge and refund are described in Notes 3 and 4, respectively. Distributions are further limited by Oncor’s required regulatory capital structure, as determined by the PUCT, to 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. For 2009, $35 million of net income was restricted from being used to make distributions on membership interests. The net proceeds of $1.253 billion received from the 2008 sale of equity interests to Texas Transmission and certain members of Oncor’s management and board of directors were excluded from these distribution limitations.

Effect of Sale of Noncontrolling Interests — The total amount of proceeds from the sale of noncontrolling interests in Oncor discussed in Note 14 was less than the carrying value of the interests sold by $265 million, which reflects the fact that Oncor’s carrying value after purchase accounting is based on the Merger value, while the noncontrolling interests sale value did not include a control premium. The difference was accounted for as a reduction of membership interests.

During the preparation of Oncor Holdings’ December 31, 2009 financial statements, Oncor Holdings determined that deferred income taxes related to its interest in Oncor should have been recorded upon the sale of noncontrolling interests in November 2008. Accordingly, the December 31, 2008 balance of noncurrent accumulated deferred income tax liabilities has been increased by $141 million (from the $1.192 billion previously reported) and total membership interests at that date has been decreased by the same amount (from the $6.801 billion previously reported). The recognition of the deferred tax liability is the result of applying rules for income tax accounting related to outside basis differences. This error did not affect net income or cash flows previously reported.

Equity Contributions — As a result of the Merger, all outstanding unvested stock-based incentive compensation awards previously granted by EFH Corp. to Oncor employees vested and such employees became entitled to receive the $69.25 per share Merger consideration. The settlement of these awards totaled $24 million and was accounted for as an equity contribution from EFH Corp., as was the settlement of $4 million of cash incentive compensation awards. See Note 18 for further discussion of stock-based compensation, including a SARs Plan implemented in November 2008.

In connection with the Merger, Texas Holdings paid a $12 million fee related to Oncor’s $2 billion revolving credit facility. Such payment was accounted for as an investment by Texas Holdings.

In March 2008, Oncor Holdings distributed its investment in an entity with telecommunications-related activities that are not part of Oncor’s current operations totaling $24 million to Intermediate Holding.

Predecessor

No shares of Oncor’s common stock were held by or for its own account, nor were any shares of such capital stock reserved for its officers and employees or for options, warrants, conversions and other rights in connection therewith.

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Under accounting standards for share-based payments, expense related to EFH Corp.’s stock-based incentive compensation awards granted to Oncor’s employees was accounted for as a noncash capital contribution from EFH Corp. Accordingly, Oncor recorded a credit to its common stock account of $3 million in the period January 1, 2007 through October 10, 2007.

Oncor recorded a credit to common stock of $15 million in the period January 1, 2007 through October 10, 2007 arising from the excess tax benefit generated by the distribution date value of the stock-based incentive awards exceeding the reported compensation expense. The $15 million credit (benefit) in 2007 was realized in the Successor period in conjunction with a tax payment to EFH Corp.

14. NONCONTROLLING INTERESTS

In November 2008, equity interests in Oncor were sold to Texas Transmission for $1.254 billion in cash. Equity interests were also indirectly sold to certain members of Oncor’s board of directors and its management team. Accordingly, after giving effect to all equity issuances, as of December 31, 2009, Oncor’s ownership was as follows: 80.03% held by Oncor Holdings, 0.22% held indirectly by Oncor’s management and board of directors and 19.75% held by Texas Transmission.

The proceeds (net of closing costs) of $1.253 billion received by Oncor from Texas Transmission and the members of Oncor management upon completion of these transactions were distributed to Oncor Holdings who distributed the proceeds to Intermediate Holding and ultimately to EFH Corp.

See Note 13 for discussion of amounts recorded as a reduction of membership interests as a result of the sale of Oncor interests.

The noncontrolling interests balance reported in the December 31, 2009 and 2008 consolidated balance sheets was $1.363 million and 1.355 billion, respectively. The noncontrolling interests balance reported in the December 31, 2009 consolidated balance sheet represented the proportional share of Oncor’s net assets at the date of the transaction less $96 million representing the noncontrolling interests’ share of Oncor’s net losses for the periods subsequent to the transaction (including the goodwill impairment charge), net of $58 million in cash distributions.

15. INVESTMENTS

The investments balance consists of the following:

	December 31, 2009		December 31, 2008
Assets related to employee benefit plans, including employee savings programs, net of distributions	$	67	$	65
Investment in unconsolidated affiliates		3		5
Land		2		2
Total investments	$	72	$	72

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. As of December 31, 2009, Oncor pays the premiums and is the beneficiary of these life insurance policies. EFH Corp. was the previous beneficiary. As of December 31, 2009 and 2008, the face amount of these policies totaled $138 million and $151 million, and the net cash surrender values totaled $52 million and $53 million, respectively. Changes in cash surrender value are netted against premiums paid. Other investment assets held to satisfy deferred compensation liabilities are recorded at market value.

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Restricted Cash

	At December 31, 2009				At December 31, 2008
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Customer collections related to securitization (transition) bonds used only to service debt and pay expenses	$	47	$	—	$	51	$	—
Reserve for fees associated with transition bonds		—		10		—		10
Reserve for shortfalls of transition bond charges		—		4		—		6
Total restricted cash	$	47	$	14	$	51	$	16

16. TERMINATION OF OUTSOURCING ARRANGEMENTS

In connection with the closing of the Merger, EFH Corp., Oncor and TCEH commenced a review, under the change of control provision, of certain outsourcing arrangements with Capgemini, Capgemini America, Inc. and Capgemini North America, Inc. (collectively, CgE). In 2008, Oncor executed a Separation Agreement with CgE. Simultaneous with the execution of that Separation Agreement, EFH Corp. and TCEH 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, each as amended, between Capgemini and each of Oncor and TCEH and the related service agreements under each of the Master Framework Agreements and (ii) termination of the joint venture arrangements between EFH Corp. (and its applicable subsidiaries) and CgE. Under the Master Framework Agreements and related services agreements, Capgemini provided to Oncor and EFH Corp. and its other subsidiaries outsourced support services, including information technology, customer care and billing, human resources, procurement and certain finance and accounting activities.

As a result, during the fourth quarter of 2008:

• EFH Corp. received approximately $70 million in cash 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 licensed assets, principally software, upon the expiration of the Master Framework Agreements in 2014 or, in some circumstances, earlier. Oncor received $20 million of such proceeds, reflecting its share of the put option value.

• The parties entered into a mutual release of all claims under the Master Framework Agreement and related services agreements, subject to certain defined exceptions, and Oncor received $4 million in cash in settlement of such claims.

The carrying value of Oncor’s share of the put option value was $48 million prior to the application of purchase accounting (recorded as a noncurrent asset). The effects of the termination of the outsourcing arrangements, including an accrued liability of $16 million for incremental costs to exit and transition the services, were included in the final purchase price allocation. See Note 2 for additional disclosure, including a reversal to income of a portion of the liability recorded in purchase accounting.

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

Pension Plan

Oncor is a participating employer in the EFH Retirement Plan (Retirement Plan), a defined benefit pension plan sponsored by EFH Corp. The Retirement Plan is a qualified pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). All benefits are funded by the participating employers. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. The interest component of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasury bonds. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs.

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All eligible employees hired after January 1, 2001 participate under the Cash Balance Formula. Certain employees who, prior to January 1, 2002, participated under the Traditional Retirement Plan Formula, continue their participation under that formula. It is EFH Corp.’s policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations.

Oncor also participated in an EFH Corp. supplemental retirement plan for certain employees, whose retirement benefits cannot be fully earned under the qualified Retirement Plan, the information for which is included below. Oncor ceased participation in the EFH Corp. plan and implemented its own supplemental retirement plan effective January 1, 2010.

OPEB Plan

Oncor participates with EFH Corp. and certain other affiliated subsidiaries of EFH Corp. to offer certain 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.

Pension and OPEB Costs Recognized as Expense

The following details net pension and OPEB costs recognized as expense:

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Pension costs	$	35		$	15		$	3		$	21
OPEB costs		55			44			9			50
Total benefit costs		90			59			12			71
Less amounts deferred principally as a regulatory asset or property		(66	)		(42	)		(8	)		(43	)
Net amounts recognized as expense	$	24		$	17		$	4		$	28

Consistent with accounting standards related to employers’ accounting for pensions, 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.

The pension and OPEB amounts provided represent allocations to Oncor of amounts related to EFH Corp.’s plans.

Regulatory Recovery of Pension and OPEB Costs

PURA provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, which in addition to Oncor’s active and retired 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. Accordingly, Oncor and TCEH entered into an agreement whereby Oncor assumed responsibility for applicable pension and OPEB costs related to those personnel.

Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Amounts deferred are ultimately subject to regulatory approval. As of December 31, 2009, Oncor had recorded regulatory assets totaling $889 million related to pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilities that otherwise would be recorded as other comprehensive income.

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Assumed Discount Rate

The discount rates reflected in net pension and OPEB costs are 6.90% (6.85% for OPEB) and 6.55% for the years ended December 31, 2009 and 2008, respectively, 6.45% for the period October 11, 2007 through December 31, 2007 and 5.90% for the period January 1, 2007 through October 10, 2007. The expected rate of return on plan assets reflected in the 2009 cost amounts is 8.25% for the pension plan and 7.64% for OPEBs.

Pension and OPEB Plan Cash Contributions

Contributions to the benefit plans were as follows:

	December 31,
	2009		2008		2007
Pension plan contributions	$	66	$	46	$	3
OPEB plan contributions		18		31		33
Total contributions	$	84	$	77	$	36

Estimated funding in 2010 of the pension and OPEB plans is $43 million and $18 million, respectively.

Thrift Plan

Employees of Oncor may participate in a qualified savings plan, the EFH Corp. Thrift Plan (Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax applicable payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under 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. Effective January 1, 2006 through October 10, 2007, employees could reallocate or transfer all or part of their accumulated or future employer matching contributions to any of the plan’s other investment options. As of October 10, 2007, employer matching contributions are made in cash and may be allocated by participants to any of the plan’s investment options. Oncor’s contributions to the Thrift Plan totaled $11 million, $9 million, $2 million and $13 million in the years ended December 31, 2009 and 2008, the period October 11, 2007 through December 31, 2007 and the period January 1, 2007 through October 10, 2007, respectively.

18. STOCK-BASED COMPENSATION

Successor

In 2008, Oncor established the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan (the SARs Plan) under which certain employees of Oncor may be granted stock appreciation rights (SARs) payable in cash, or in some circumstances, Oncor units. Two types of SARs may be granted under the SARs Plan. Time-based SARs (Time SARs) vest solely based upon continued employment ratably on an annual basis on each of the first five anniversaries of the grant date. Performance-based SARs (Performance SARs) vest based upon both continued employment and the achievement of a predetermined level of Oncor EBITDA over time, generally ratably over five years based upon annual Oncor EBITDA levels, with provisions for vesting if the annual levels are not achieved but cumulative two- or three-year total Oncor EBITDA levels are achieved. Time and Performance SARs may also vest in part or in full upon the occurrence of certain specified liquidity events and are exercisable only upon the occurrence of certain specified liquidity events. Since the exercisability of the Time and Performance SARs is conditioned upon the occurrence of a liquidity event, compensation expense will not be recorded until it is probable that a liquidity event will occur. Generally, awards under the SARs Plan terminate on the tenth anniversary of the grant, unless the participant’s employment is terminated earlier under certain circumstances.

F-187

In February 2009, Oncor also established the Oncor Electric Delivery Company LLC Director Stock Appreciation Rights Plan (the Director SARs Plan) under which certain non-employee members of Oncor’s board of directors and other persons having a relationship with Oncor may be granted SARs payable in cash, or in some circumstances, Oncor units. SARs granted under the Director SARs Plan vest in eight equal quarterly installments over a two-year period and are exercisable only upon the occurrence of certain specified liquidity events. Since the exercisability of these SARs is conditioned upon the occurrence of a liquidity event, expense will not be recorded until it is probable a liquidity event will occur.

SARs under the SARs Plan and the Director SARs Plan are generally payable in cash based on the fair market value of the SAR on the date of exercise. No SARs were granted under the SARs Plan during the year ended December 31, 2009. Oncor granted 6.9 million Time SARs under the SARs Plan during the year ended December 31, 2008, and Time SARS vested at December 31, 2009 totaled 2.8 million. Oncor granted 6.9 million Performance SARs under the SARs Plan during the year ended December 31, 2008, and Performance SARs vested at December 31, 2009 totaled 1.4 million. Oncor granted 55 thousand SARs under the Director SARs Plan during the year ended December 31, 2009, and SARs vested under the Director SARs Plan at December 31, 2009 totaled 27.5 thousand. There were no SARs under either plan eligible for exercise at December 31, 2009.

Predecessor

Prior to the Merger, Oncor bore the costs of the EFH Corp. shareholder-approved long-term incentive plans for applicable management personnel engaged in Oncor’s business activities. EFH Corp. provided discretionary awards of performance units to qualified management employees that were payable in its common stock. The awards generally vested over a three-year period, and the number of shares ultimately earned was based on the performance of EFH Corp.’s stock over the vesting period as compared to peer companies and established thresholds. EFH Corp. established restrictions that limited certain employees’ opportunities to liquidate vested awards.

EFH Corp. determined the fair value of its stock-based compensation awards utilizing a valuation model that took into account three principal factors: expected volatility of the stock price of EFH Corp. and peer group companies, dividend rate of EFH Corp. and peer group companies and the restrictions limiting liquidation of vested stock awards. Based on the fair values determined under this model, Oncor’s reported expense related to the awards totaled $3 million ($2 million after-tax) for the period January 1, 2007 through October 10, 2007. There were no awards granted in 2007.

With respect to awards to Oncor’s employees, the fair value of awards that vested in the period January 1, 2007 through October 10, 2007 totaled $84 million based on the vesting date share prices.

19. RELATED-PARTY TRANSACTIONS

The following represent significant related-party transactions of Oncor Holdings:

• Oncor records revenue from TCEH, principally for electricity delivery fees, which totaled $1.0 billion for each of the years ended December 31, 2009 and 2008, $209 million for the period October 11, 2007 through December 31, 2007 and $823 million for the period January 1, 2007 through October 10, 2007.

• Oncor records interest income from TCEH with respect to Oncor’s generation-related regulatory assets, which have been securitized through the issuance of transition bonds by Oncor’s bankruptcy-remote financing subsidiary. The interest income serves to offset Oncor’s interest expense on the transition bonds. This interest income totaled $42 million and $46 million for the years ended December 31, 2009 and 2008, respectively, $11 million for the period October 11, 2007 through December 31, 2007 and $38 million for the period January 1, 2007 through October 10, 2007.

• Incremental amounts payable by Oncor related to income taxes as a result of delivery fee surcharges to its customers related to transition bonds are reimbursed by TCEH. Oncor Holdings’ financial statements reflect a note receivable from TCEH to Oncor of $254 million ($37 million reported as current in trade accounts and other receivables from affiliates) at December 31, 2009 and $289 million ($35 million reported as current in trade accounts and other receivables from affiliates) at December 31, 2008 related to these income taxes.

F-188

• As a result of actions taken at the time of the Merger to further ring-fence Oncor, short-term advances from EFH Corp. to Oncor ceased and outstanding amounts were repaid. The average daily balances of short-term advances from parent totaled $42 million for the period January 1, 2007 through October 10, 2007, and the weighted average interest rate for the period was 5.8%. Interest expense incurred on the advances totaled approximately $2 million for the period January 1, 2007 through October 10, 2007.

• An EFH Corp. subsidiary charges Oncor for financial and certain other administrative services at cost. These costs, which are reported in operation and maintenance expenses, totaled $22 million and $24 million for the years ended December 31, 2009 and 2008, respectively, $6 million for the period October 11, 2007 through December 31, 2007 and $20 million for the period January 1, 2007 through October 10, 2007.

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility (reported on TCEH’s balance sheet) is funded by a delivery fee surcharge collected from REPs by Oncor and remitted to TCEH. These trust fund assets are established with the intent to be sufficient to fund the estimated decommissioning liability (also reported on TCEH’s balance sheet). Income and expenses associated with the trust fund and the decommissioning liability recorded by TCEH are offset by a net change in the Oncor and TCEH intercompany receivable/payable, which in turn results in a change in Oncor’s reported net regulatory asset/liability. The regulatory asset of $85 million and $127 million at December 31, 2009 and 2008, respectively, represents the excess of the net decommissioning liability over the trust fund balance.

• Oncor has a 19.5% limited partnership interest, with a carrying value of $3 million and $5 million at December 31, 2009 and 2008, respectively, in an EFH Corp. subsidiary holding principally software-related assets. Equity losses related to this interest are reported in other deductions and totaled $2 million and $4 million for the years ended December 31, 2009 and 2008, respectively, $1 million for the period October 11, 2007 through December 31, 2007 and $2 million for the period January 1, 2007 through October 10, 2007. These losses primarily represent amortization of software assets held by the subsidiary.

• EFH Corp. files a consolidated federal income tax return and allocates income tax liabilities to Oncor Holdings under a tax sharing agreement substantially as if Oncor Holdings was filing its own income tax returns. Oncor Holdings’ results are included in the consolidated Texas state margin tax return filed by EFH Corp. Oncor Holdings’ amount payable to EFH Corp. related to income taxes totaled $5 million at December 31, 2009, and amount receivable from EFH Corp. related to income taxes, primarily due to timing of payments, totaled $22 million at December 31, 2008. Income tax payments in the year ended December 31, 2009 totaled $19 million to EFH Corp., and Oncor made federal income tax payments totaling $9 million to noncontrolling interests.

• Oncor held cash collateral of $15 million on both December 31, 2009 and 2008 from TCEH related to interconnection agreements for three generation units being developed by TCEH. The collateral is reported in the balance sheet in other current liabilities.

• Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, as of December 31, 2009 and 2008, TCEH had posted letters of credit in the amount of $15 million and $13 million, respectively, for Oncor’s benefit.

F-189

• At the closing of the Merger, Oncor entered into its current $2 billion revolving credit facility with a syndicate of financial institutions and other lenders. The syndicate includes affiliates of GS Capital Partners. Affiliates of GS Capital Partners (a member of the Sponsor Group) have from time-to-time engaged in commercial banking transactions with Oncor Holdings or its subsidiaries in the normal course of business.

• Affiliates of the Sponsor Group have, and may, sell, acquire or participate in the offerings of debt or debt securities issued by Oncor Holdings or its subsidiaries in open market transactions or through loan syndications.

See Notes 7, 9, 13 and 17 for information regarding the tax sharing agreement, the accounts receivable securitization program, distributions to Intermediate Holding and the allocation of EFH Corp.’s pension and OPEB costs to Oncor, respectively.

20. SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions

	Successor						Predecessor
	Year Ended December 31, 2009		Year Ended December 31, 2008		Period from October 11, 2007 through December 31, 2007		Period from January 1, 2007 through October 10, 2007
Other income:
Accretion of adjustment (discount) to regulatory assets due to purchase accounting (Note 2)	$	39	$	44	$	10	$	—
Reversal of exit liabilities recorded in connection with the termination of outsourcing arrangements (see Note 2)		10		—		—		—
Net gain on sale of other properties and investments		—		1		1		3
Total other income	$	49	$	45	$	11	$	3
Other deductions:
Costs related to 2006 cities rate settlement (Note 5)	$	2	$	13	$	6	$	20
Professional fees		5		5		1		5
Equity losses in unconsolidated affiliate (Note 19)		2		4		1		2
Expenses related to canceled InfrastruX Energy services joint venture (a)		—		—		—		3
Other		5		3		—		—
Total other deductions	$	14	$	25	$	8	$	30

(a) Consists of previously deferred costs arising from operational activities to transition to the joint venture arrangement, which was canceled in connection with the Merger.

Major Customers

Distribution revenues from TCEH represented 38% and 39% of total operating revenues for the years ended December 31, 2009 and 2008, respectively, 39% for the period October 11, 2007 through December 31, 2007 and 42% for the period January 1, 2007 through October 10, 2007. Revenues from subsidiaries of one nonaffiliated REP collectively represented 14% and 16% of total operating revenues for the years ended December 31, 2009 and 2008, respectively, 15% for the period October 11, 2007 through December 31, 2007 and 16% for the period January 1, 2007 through October 10, 2007. No other customer represented 10% or more of total operating revenues.

F-190

Interest Expense and Related Charges

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Interest	$	338		$	314		$	70		$	242
Amortization of fair value debt discounts resulting from purchase accounting		3			3			—			—
Amortization of debt issuance costs and discounts		7			5			1			7
Allowance for funds used during construction — capitalized interest portion		(2	)		(6	)		(1	)		(7	)
Total interest expense and related charges	$	346		$	316		$	70		$	242

Property, Plant and Equipment

	December 31, 2009		December 31, 2008
Assets in service:
Distribution	$	8,778	$	8,429
Transmission		3,917		3,626
Other assets		579		477
Total		13,274		12,532
Less accumulated depreciation		4,444		4,158
Net of accumulated depreciation		8,830		8,374
Construction work in progress		321		213
Held for future use		23		19
Property, plant and equipment — net	$	9,174	$	8,606

Depreciation expense as a percent of average depreciable property approximated 3.1% for 2009 and 2.8% for 2008 and 2007.

Intangible Assets

Intangible assets other than goodwill reported in the balance sheet are comprised of the following:

	As of December 31, 2009						As of December 31, 2008
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Intangible assets subject to amortization included in property, plant and equipment:
Land easements	$	188	$	72	$	116	$	184	$	69	$	115
Capitalized software		240		104		136		145		80		65
Total	$	428	$	176	$	252	$	329	$	149	$	180

Aggregate amortization expense for intangible assets totaled $27 million and $19 million for the years ended December 31, 2009 and 2008, respectively, $3 million for the period October 11, 2007 through December 31, 2007 and $11 million for the period January 1, 2007 through October 10, 2007. At December 31, 2009, the weighted average remaining useful lives of capitalized land easements and software were 67 years and 6 years, respectively. The estimated aggregate amortization expense for each of the next five fiscal years is as follows:

Year	Amortization Expense
2010	$	32
2011		23
2012		21
2013		21
2014		21

F-191

At December 31, 2009 and 2008, goodwill of $4.1 billion was reported on the balance sheet. None of this goodwill is being deducted for tax purposes. This balance is net of the $860 million goodwill impairment charge recorded in the fourth quarter of 2008. No other impairments have been recorded since the Merger. See Note 2 for discussion of financial statement effects of the Merger, and Note 3 for discussion of the goodwill impairment.

Other Noncurrent Liabilities and Deferred Credits

The other noncurrent liabilities and deferred credits balance consists of the following:

	Successor
	December 31, 2009		December 31, 2008
Retirement plan and other employee benefits	$	1,343	$	1,115
Liabilities related to subsidiary tax sharing agreement		321		299
Uncertain tax positions (including accrued interest)		91		144
Nuclear decommissioning cost under-recovery (a)		85		127
Other		39		35
Total other noncurrent liabilities and deferred credits	$	1,879	$	1,720

(a) Represents intercompany payable to TCEH offset in Oncor’s net reported regulatory asset/liability. See Note 8.

Liabilities Related to Subsidiary Tax Sharing Agreement — Amount represents the previously recorded net deferred tax liabilities of Oncor related to the noncontrolling interests. Upon the sale of noncontrolling interests in Oncor (see Note 14), Oncor became a partnership for US federal income tax purposes, and the temporary differences which gave rise to the deferred taxes will, over time, become taxable to the noncontrolling interests. Under a tax sharing agreement among Oncor and its equity holders, Oncor reimburses its equity holders for federal income taxes as the partnership earnings become taxable to such holders. Accordingly, as the temporary differences become taxable, the equity holders will be reimbursed by Oncor. In the unlikely event such amounts are not reimbursed under the tax sharing agreement, it is probable they would be refunded to rate payers. The net changes in the liability for the year ended December 31, 2009 totaling $22 million reflected changes in temporary differences.

Supplemental Cash Flow Information

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Cash payments:
Interest paid	$	337		$	284		$	72		$	240
Capitalized interest		(2	)		(6	)		(1	)		(7	)
Interest (net of amounts capitalized)		335			278			71			233
Income taxes		28			65			26			106
Noncash investing and financing activities:
Noncash construction expenditures (a)		61			49			70			25
Noncash capital contribution related to settlement of certain income taxes payable (b)		50			—			—			—
Noncash distribution of investment to parent		—			24			—			—
Noncash contribution related to incentive compensation plans		—			—			28			—
Noncash capital contribution from Texas Holdings		—			—			12			—

(a) Represents end-of-period accruals.

(b) Reflects noncash settlement of certain income taxes payable arising as a result of the sale of noncontrolling interests in Oncor.

F-192

21. CONDENSED FINANCIAL INFORMATION OF REGISTRANT

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF INCOME (LOSS)

(millions of dollars)

	Successor							Predecessor
	Year Ended December 31, 2009		Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007		Period from January 1, 2007 through October 10, 2007
Income tax benefit	$	—	$	4		$	—	$	—
Equity in earnings (losses) of subsidiary		256		(327	)		64		263
Net income (loss)	$	256	$	(323	)	$	64	$	263

See Notes to Financial Statements.

F-193

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(millions of dollars)

	Successor									Predecessor
	Year Ended December 31, 2009			Year Ended December 31, 2008			Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007
Cash flows — operating activities:
Net income	$	256		$	(323	)	$	64		$	263
Adjustments to reconcile net income to cash provided by operating activities:
Equity in (earnings) losses of subsidiaries		(256	)		327			(64	)		(263	)
Deferred income taxes — net		(50	)		(4	)		—			—
Net changes in operating assets and liabilities		266			331			—			—
Cash provided by operating activities		216			331			—			—
Cash flows — financing activities:
Proceeds from sale of noncontrolling interests, net of transaction costs (Note 14)		—			1,253			—			—
Distribution to parent of equity sale net proceeds		—			(1,253	)		—			—
Distributions to parent		(216	)		(330	)		—			—
Cash used in financing activities		(216	)		(330	)		—			—
Cash flows — investing activities:
Cash used in investing activities		—			—			—			—
Net change in cash and cash equivalents		—			1			—			—
Cash and cash equivalents — beginning balance		1			—			—			—
Cash and cash equivalents — ending balance	$	1		$	1		$	—		$	—

See Notes to Financial Statements.

F-194

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(millions of dollars)

	Successor
	December 31, 2009		December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	1	$	1
Income taxes receivable from EFH Corp.		3		1
Other current assets		2		2
Total current assets		6		4
Investments		5,804		5,741
Total assets	$	5,810	$	5,745
LIABILITIES AND MEMBERSHIP INTEREST
Current liabilities:
Other current liabilities	$	3	$	—
Total current liabilities		3		—
Accumulated deferred income taxes		91		141
Other noncurrent liabilities and deferred credits		321		299
Total liabilities		415		440
Membership interest		5,395		5,305
Total liabilities and membership interest	$	5,810	$	5,745

See Notes to Financial Statements.

F-195

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO CONDENSED FINANCIAL STATEMENTS

Basis of Presentation

The accompanying unconsolidated condensed balance sheets, statements of income (loss) and cash flows present results of operations and cash flows of Oncor Holdings for periods subsequent to the Merger, at which time Oncor Holdings was formed. Oncor Holdings, which is a Delaware limited liability company wholly-owned by Intermediate Holding, is the holding company for approximately 80% of the membership interests in Oncor as of December 31, 2009. The financial statements reflect the application of purchase accounting for the Merger at Oncor. 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 Oncor Holdings’ consolidated financial statements and Notes 1 through 20. Oncor Holdings’ 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. The predecessor to Oncor Holdings is Oncor. Accordingly, Predecessor amounts in the accompanying unconsolidated condensed statements of income (loss) and cash flows reflect Oncor’s results accounted for under the equity method. The financial statements of Oncor are presented as the Predecessor of Oncor Holdings’ historical consolidated financial statements and related notes.

Distribution Restrictions

While there are no direct restrictions on Oncor Holdings’ ability to distribute its net income that are currently material, substantially all of Oncor Holdings’ net income is derived from Oncor. The boards of directors of each of Oncor and Oncor Holdings, which are composed of a majority of independent directors, can withhold distributions to the extent the boards determine that it is necessary to retain such amounts to meet expected future requirements of Oncor and/or Oncor Holdings. For the period beginning October 11, 2007 and ending December 31, 2012, distributions paid by Oncor (other than distributions of the proceeds of any issuance of limited liability company units) are limited by the Limited Liability Company Agreement to an amount not to exceed Oncor’s net cumulative income determined in accordance with GAAP, as adjusted by applicable orders of the PUCT. Such adjustments include deducting the $72 million ($46 million after tax) one-time refund to customers in September 2008 and deducting funds spent as part of the $100 million commitment for additional demand-side management or other energy efficiency initiatives (see Note 4) of which $22 million ($14 million after tax) has been spent through December 31, 2009, neither of which impacted net income due to purchase accounting, and removing the effect of the $860 million goodwill impairment charge from fourth quarter 2008 net income available for distribution. The goodwill impairment charge and refund are described in Notes 3 and 4, respectively. Distributions are further limited by Oncor’s required regulatory capital structure, as determined by the PUCT, to 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. For 2009, $35 million of net income was restricted from being used to make distributions on membership interests. The net proceeds of $1.253 billion received from the 2008 sale of equity interests to Texas Transmission and certain members of Oncor’s management and board of directors were excluded from these distribution limitations.

On February 11, 2010, Oncor’s board of directors declared a cash distribution of between $34 million and $41 million to be paid to Oncor Holdings on February 19, 2010. During 2009 and 2008, Oncor’s board of directors declared, and Oncor paid, cash distributions to Oncor Holdings totaling $216 million and $330 million, respectively. No dividends were received for the period from October 11, 2007 through December 31, 2007.

The net proceeds of $1.253 billion from Oncor’s sale of equity interests in November 2008 were distributed to Intermediate Holding and ultimately to EFH Corp.

F-196

GLOSSARY

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

2009 Audited Financial Statements Oncor Holdings’ audited financial statements for the year ended December 31, 2009 included in EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2009 filed on February 19, 2010 (Commission File No. 1-12833)

Bondco Refers to Oncor Electric Delivery Transition Bond Company LLC, a wholly-owned consolidated bankruptcy-remote financing subsidiary of Oncor.

Deed of Trust Deed of Trust, Security Agreement and Fixture Filing, dated as of May 15, 2008, made by Oncor to and for the benefit of The Bank of New York Mellon (formerly The Bank of New York), as collateral agent, as amended

EFH Corp. Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include Oncor and TCEH.

EFIH Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.

ERCOT Electric Reliability Council of Texas, the independent system operator and the regional coordinator of the various electricity systems within Texas

FASB Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting

FERC US Federal Energy Regulatory Commission

GAAP generally accepted accounting principles

Investment LLC Refers to Oncor Management Investment LLC, a limited liability company and minority membership interest owner of Oncor, whose managing member is Oncor and whose Class B Interests are owned by officers, directors and key employees of Oncor.

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.

Limited Liability Company Agreement The Second Amended and Restated Limited Liability Company Agreement of Oncor, dated as of November 5, 2008, by and among Oncor Holdings, Texas Transmission and Investment LLC, as amended

Luminant Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.

Merger The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007.

Merger Agreement Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.

Oncor Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings, and/or its wholly-owned consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context.

F-197

Oncor Holdings Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context.

Oncor Ring-Fenced Entities Refers to Oncor Holdings and its direct and indirect subsidiaries.

OPEB other postretirement employee benefits

PUCT Public Utility Commission of Texas

purchase accounting The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs, are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.

REP retail electric provider

SEC US Securities and Exchange Commission

Sponsor Group Refers collectively to the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P. (KKR), 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 Energy Future Competitive Holdings Company and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context.

Texas Holdings Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.

Texas Holdings Group Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities.

Texas Transmission Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of EFH Corp.’s subsidiaries or any member of the Sponsor Group.

TXU Energy Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT.

US United States of America

VIE variable interest entity

These financial statements occasionally make references to Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or any other affiliate.

F-198

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(millions of dollars)
Operating revenues:
Affiliated	$	317		$	308		$	839		$	783
Nonaffiliated		514			462			1,397			1,254
Total operating revenues		831			770			2,236			2,037
Operating expenses:
Operation and maintenance		256			245			757			698
Depreciation and amortization		176			147			507			405
Write off of regulatory assets (Note 2)		—			25			—			25
Income taxes		73			49			156			122
Taxes other than income taxes		100			99			287			287
Total operating expenses		605			565			1,707			1,537
Operating income		226			205			529			500
Other income and deductions:
Other income (Note 9)		8			10			28			30
Other deductions (Note 9)		1			5			5			14
Nonoperating income taxes		7			7			21			19
Interest income		9			13			29			32
Interest expense and related charges (Note 9)		87			85			259			258
Net income		148			131			301			271
Net income attributable to noncontrolling interests		(30	)		(26	)		(61	)		(54	)
Net income attributable to Oncor Holdings	$	118		$	105		$	240		$	217

See Notes to Financial Statements.

F-199

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2010			2009
	(millions of dollars)
Cash flows — operating activities:
Net income	$	301		$	271
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		510			379
Write off of regulatory assets (Note 2)		—			25
Deferred income taxes – net		105			63
Amortization of investment tax credits		(3	)		(4	)
Other – net		—			(2	)
Changes in operating assets and liabilities:
Deferred advanced metering system revenues		11			51
Other operating assets and liabilities		(201	)		(129	)
Cash provided by operating activities		723			654
Cash flows — financing activities:
Issuance of long-term debt (Note 4)		475			—
Repayments of long-term debt (Note 4)		(72	)		(70	)
Net increase (decrease) in short-term borrowings		(188	)		200
Distributions to parent		(141	)		(117	)
Distributions to noncontrolling interests		(35	)		(32	)
Decrease in income tax-related note receivable from TCEH		27			27
Debt discount, financing and reacquisition expenses – net		(11	)		(3	)
Cash provided by financing activities		55			5
Cash flows — investing activities:
Capital expenditures		(782	)		(758	)
Other		(14	)		(4	)
Cash used in investing activities		(796	)		(762	)
Net change in cash and cash equivalents		(18	)		(103	)
Cash and cash equivalents — beginning balance		29			126
Cash and cash equivalents — ending balance	$	11		$	23

See Notes to Financial Statements.

F-200

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2010		December 31, 2009
	(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	11	$	29
Restricted cash (relates to Bondco (Note 9))		63		47
Trade accounts receivable from nonaffiliates — net (Note 9)		291		243
Trade accounts and other receivables from affiliates		220		188
Income taxes receivable from EFH Corp. (Note 8)		59		—
Materials and supplies inventories — at average cost		94		92
Accumulated deferred income taxes		1		10
Prepayments		75		76
Other current assets		4		8
Total current assets		818		693
Restricted cash (relates to Bondco (Note 9))		16		14
Investments and other property (Note 9)		76		72
Property, plant and equipment — net (Note 9)		9,529		9,174
Goodwill (Note 9)		4,064		4,064
Note receivable due from TCEH (Note 8)		189		217
Regulatory assets — net (2010 includes $531 related to Bondco (Notes 2 and 9))		1,652		1,959
Other noncurrent assets		238		51
Total assets	$	16,582	$	16,244
LIABILITIES AND MEMBERSHIP INTERESTS
Current liabilities:
Short-term borrowings (Note 3)	$	428	$	616
Long-term debt due currently (relates to Bondco (Notes 4 and 9))		111		108
Trade accounts payable		111		129
Income taxes payable to EFH Corp. (Note 8)		—		5
Accrued taxes other than income		116		137
Accrued interest		73		104
Other current liabilities		94		106
Total current liabilities		933		1,205
Accumulated deferred income taxes		1,478		1,369
Investment tax credits		34		37
Long-term debt, less amounts due currently (2010 includes $588 related to Bondco (Notes 4 and 9))		5,395		4,996
Other noncurrent liabilities and deferred credits (Note 9)		1,775		1,879
Total liabilities		9,615		9,486
Commitments and Contingencies (Note 5)
Membership interests (Note 6):
Oncor Holdings membership interest		5,525		5,395
Noncontrolling interests in subsidiary		1,442		1,363
Total membership interests		6,967		6,758
Total liabilities and membership interests	$	16,582	$	16,244

See Notes to Financial Statements.

F-201

ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. SIGNIFICANT ACCOUNTING POLICIES AND BUSINESS

Description of Business

Oncor Holdings is a Dallas, Texas-based holding company whose financial statements reflect almost entirely the operations of its direct, majority (approximately 80%) owned subsidiary, Oncor. Oncor is a regulated electricity transmission and distribution company principally engaged in providing delivery services to REPs, including subsidiaries of TCEH, that sell power in the north-central, eastern and western parts of Texas. Distribution revenues from TCEH represented 38% of total revenues for both the nine months ended September 30, 2010 and 2009. Oncor Holdings is a direct, wholly-owned subsidiary of EFIH, a direct, wholly-owned subsidiary of EFH Corp. With the closing of the Merger on October 10, 2007, EFH Corp. became a subsidiary of Texas Holdings, which is controlled by the Sponsor Group, and Oncor Holdings and EFIH were formed. See “Glossary” for definition of terms and abbreviations, including the Merger. References in this report to Oncor Holdings are to Oncor Holdings and/or its direct or indirect subsidiaries as apparent in the context. Oncor Holdings’ financial statements reflect almost entirely the operations of Oncor, which is managed as an integrated business; consequently, there are no separate reportable business segments.

Oncor Holdings’ consolidated financial statements include Bondco.

Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor Holdings and Oncor. These measures serve to mitigate Oncor’s and Oncor Holdings’ credit exposure to the Texas Holdings Group and to reduce the risk that the assets and liabilities of Oncor or Oncor Holdings would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities. Such measures include, among other things: Oncor’s sale of a 19.75% equity interest to Texas Transmission in November 2008; maintenance of separate books and records for the Oncor Ring-Fenced Entities; the board of directors of Oncor Holdings and Oncor being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities’ providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group, including TXU Energy and Luminant, and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or contractual obligations of any member of the Texas Holdings Group. Oncor and Oncor Holdings do not bear any liability for debt or contractual obligations of the Texas Holdings Group, and vice versa. Accordingly, Oncor Holdings’ operations are conducted, and its cash flows managed, independently from the Texas Holdings Group.

Basis of Presentation

The condensed consolidated financial statements of Oncor Holdings have been prepared in accordance with US GAAP and on the same basis as the 2009 Audited Financial Statements. 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 2009 Audited Financial Statements. 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. Subsequent events have been evaluated through November 2, 2010, the date these consolidated financial statements were issued.

F-202

Use of Estimates

Preparation of Oncor Holdings’ 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.

2.    REGULATORY ASSETS AND LIABILITIES

Recognition of regulatory assets and liabilities and the amortization periods over which they are expected to be recovered or refunded through rate regulation reflect the decisions of the PUCT. Components of the regulatory assets and liabilities are provided in the table below. Amounts not earning a return through rate regulation are noted.

	Remaining Rate Recovery/Amortization Period at September 30, 2010		Carrying Amount
			September 30, 2010		December 31, 2009
Regulatory assets:
Generation-related regulatory assets securitized by transition bonds (a)		6 years	$	677	$	759
Employee retirement costs		4 years		67		80
Employee retirement costs to be reviewed (b)(c)		To be determined		66		41
Employee retirement liability (a)(c)(d)		To be determined		726		768
Self-insurance reserve (primarily storm recovery costs) — net		6 years		122		137
Self-insurance reserve to be reviewed (b)(c)		To be determined		139		106
Nuclear decommissioning cost under-recovery (a)(c)(e)		Not applicable		—		85
Securities reacquisition costs (pre-industry restructure)		7 years		57		62
Securities reacquisition costs (post-industry restructure)		Terms of related debt		26		27
Recoverable amounts in lieu of deferred income taxes — net		Life of related asset or liability		107		68
Rate case expenses		Largely 3 years		7		9
Rate case expenses to be reviewed (b)(c)		To be determined		2		1
Advanced meter customer education costs		10 years		7		4
Deferred conventional meter depreciation		10 years		49		14
Energy efficiency performance bonus (a)		1 year		2		9
Total regulatory assets				2,054		2,170
Regulatory liabilities:
Nuclear decommissioning cost over-recovery (a)(e)		Not applicable		183		—
Committed spending for demand-side management initiatives (a)		3 years		65		78
Deferred advanced metering system revenues		10 years		68		57
Investment tax credit and protected excess deferred taxes		Various		41		44
Over-collection of securitization (transition) bond revenues (a)		6 years		39		27
Energy efficiency programs (a)		Not applicable		6		5
Total regulatory liabilities				402		211
Net regulatory asset			$	1,652	$	1,959

(a) Not earning a return in the regulatory rate-setting process.

(b) Costs incurred since the period covered under the last rate review.

(c) Recovery is specifically authorized by statute, subject to reasonableness review by the PUCT.

(d) Represents unfunded liabilities recorded in accordance with pension and OPEB accounting standards.

(e) Offset by an intercompany payable to/receivable from TCEH. See Note 8.

F-203

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act enacted in March 2010 reduce, effective 2013, the amount of OPEB costs deductible for federal income tax purposes by the amount of the Medicare Part D subsidy received by the EFH Corp. OPEB plans in which Oncor participates. Under income tax accounting rules, deferred tax assets related to accrued OPEB liabilities must be reduced immediately for the future effect of the legislation. Accordingly, in the first quarter of 2010, Oncor Holdings’ deferred tax assets were reduced by $42 million. All of this amount was recorded as a regulatory asset (before gross-up for liability in lieu of deferred income taxes) as the additional amounts due related to income taxes are expected to be recoverable in Oncor’s future rates.

As part of accounting for the Merger, the carrying value of certain generation-related regulatory assets securitized by transition bonds, which have been reviewed and approved by the PUCT for recovery but without earning a rate of return, was reduced by $213 million. This amount will be accreted to other income over the recovery period remaining as of the closing date of the Merger (approximately nine years).

On August 31, 2009, the PUCT issued a final order on Oncor’s rate review filed in June 2008. The rate review included a determination of the recoverability of regulatory assets at December 31, 2007, including the recoverability period of those assets deemed allowable by the PUCT. The PUCT’s findings included denial of recovery of certain regulatory assets primarily related to business restructuring costs and rate case expenses, which resulted in a $25 million charge ($16 million after tax) in the third quarter 2009 reported as write off of regulatory assets.

3.    BORROWINGS UNDER CREDIT FACILITIES

At September 30, 2010, Oncor had a $2.0 billion secured revolving credit facility, expiring October 10, 2013, to be used for its working capital and general corporate purposes, issuances of letters of credit and support for any commercial paper issuances. Oncor may request increases in the commitments under the facility in any amount up to $500 million, subject to the satisfaction of certain conditions. Amounts borrowed under the facility, once repaid, can be borrowed again by Oncor from time to time. Borrowings are classified as short-term on the balance sheet.

The credit facility is secured equally and ratably with all of Oncor’s other secured indebtedness by a first priority lien on property acquired or constructed by Oncor for the transmission and distribution of electricity. The property is mortgaged under the Deed of Trust. On September 3, 2010, Oncor amended the Deed of Trust to eliminate Oncor’s ability to release the lien upon satisfaction and discharge of its obligations under the revolving credit facility (see Note 4).

At September 30, 2010, Oncor had outstanding borrowings under the credit facility totaling $428 million with an interest rate of 0.53% and outstanding letters of credit totaling $6 million. At December 31, 2009, Oncor had outstanding borrowings under the credit facility totaling $616 million with an interest rate of 0.58% at the end of the period. All outstanding borrowings at September 30, 2010 bear interest at LIBOR plus 0.275%, letters of credit bear interest at 0.275%, and a facility fee is payable (currently at a rate per annum equal to 0.100%) on the commitments under the facility, each based on Oncor’s current credit ratings.

Subject to the limitations described below, borrowing capacity availability under the credit facility at September 30, 2010 and December 31, 2009 was $1.444 billion and $1.262 billion, respectively. The availability at both dates excludes $122 million of commitments from a subsidiary of Lehman Brothers Holding Inc. (such subsidiary, Lehman) that has filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 10 to the 2009 Audited Financial Statements for additional information. As described in Note 4, the availability under the credit facility is limited by the amount of available bond credits, which was approximately $1.338 billion at September 30, 2010. However, at September 30, 2010, Oncor could secure up to an additional $1.040 billion of potential indebtedness with certain property additions, subject to the completion of a certification process.

F-204

4.    LONG-TERM DEBT

At September 30, 2010 and December 31, 2009, long-term debt consisted of the following:

	September 30, 2010			December 31, 2009
Oncor (a):
6.375% Fixed Senior Notes due May 1, 2012	$	700		$	700
5.950% Fixed Senior Notes due September 1, 2013		650			650
6.375% Fixed Senior Notes due January 15, 2015		500			500
6.800% Fixed Senior Notes due September 1, 2018		550			550
7.000% Fixed Debentures due September 1, 2022		800			800
7.000% Fixed Senior Notes due May 1, 2032		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
7.500% Fixed Senior Notes due September 1, 2038		300			300
5.250% Fixed Senior Notes due September 30, 2040		475			—
Unamortized discount		(18	)		(15	)
Total Oncor	$	4,807		$	4,335
Oncor Electric Delivery Transition Bond Company LLC (b):
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		—			13
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		101			130
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		145			145
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		167			197
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		290			290
Total Oncor Electric Delivery Transition Bond Company LLC		703			775
Unamortized fair value discount related to transition bonds (c)		(4	)		(6	)
Total consolidated (d)		5,506			5,104
Less amount due currently		(111	)		(108	)
Total long-term debt	$	5,395		$	4,996

(a) Secured by first priority lien on certain transmission and distribution assets equally and ratably with all of Oncor’s other secured indebtedness. See Deed of Trust Amendment below and Note 11 to the 2009 Audited Financial Statements for additional information.

(b) The transition bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset.

(c) The transition bonds, which secured regulatory assets not earning a return, were fair valued at October 10, 2007 as a result of purchase accounting.

(d) According to its organizational documents, Oncor Holdings (parent) is prohibited from directly incurring indebtedness for borrowed money.

Debt-Related Activity in 2010

Repayments of long-term debt in 2010 totaled $72 million and represent transition bond principal payments at scheduled maturity dates.

Issuance of New Senior Secured Notes

In September 2010, Oncor issued $475 million aggregate principal amount of 5.250% senior secured notes maturing in September 2040 (2040 Notes). Oncor used the net proceeds of approximately $465 million from the sale of the notes to repay borrowings under its revolving credit facility, including loans under the revolving credit facility made by certain of the initial purchasers or their affiliates, and for general corporate purposes. The notes are secured by the first priority lien described below, and are secured equally and ratably with all of Oncor’s other secured indebtedness.

F-205

Interest on the 2040 Notes is payable in cash semiannually in arrears on March 30 and September 30 of each year, beginning on March 30, 2011. Oncor may redeem the notes, in whole or in part, at any time, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. The notes also contain customary events of default, including failure to pay principal or interest on the notes when due.

The 2040 Notes were issued in a private placement and have not been registered under the Securities Act of 1933, as amended (Securities Act). Oncor has agreed, subject to certain exceptions, to register with the SEC notes having substantially identical terms as the 2040 Notes (except for provisions relating to the transfer restriction and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the 2040 Notes. Oncor has agreed to use commercially reasonable efforts to cause the exchange offer to be completed within 315 days after the issue date of the 2040 Notes, or if required, to use commercially reasonable efforts to have one or more shelf registration statements declared effective within the later of 180 days after such shelf registration statement filing obligation arises and 270 days after the issue date of the Notes. If Oncor does not comply with this obligation (a registration default), the annual interest rate on the notes will increase by 0.50% per annum until the earlier of the expiration of the registration default or the second anniversary of the issue date of the 2040 Notes.

Debt Exchange

In September 2010, Oncor announced an offer to exchange up to $350 million of its outstanding 6.375% senior secured notes due 2012 and up to $325 million of its outstanding 5.950% senior secured notes due 2013 (collectively, the Original Notes) for newly issued 5.000% senior secured notes due 2017 (2017 Notes) and newly issued 5.750% senior secured notes due 2020 (2020 Notes, and together with the 2017 Notes, New Notes), respectively. The exchange offer expired on October 5, 2010 and settled on October 8, 2010. At settlement, Oncor issued approximately $324.4 million aggregate principal amount of the 2017 Notes and approximately $126.3 million aggregate principal amount of the 2020 Notes in exchange for an equivalent principal amount of the respective Original Notes validly tendered. Oncor did not receive any cash proceeds from the exchange.

The New Notes have not been registered under the Securities Act. In connection with the issuance of the New Notes, Oncor agreed, subject to certain exceptions, to register with the SEC notes having substantially identical terms as the New Notes (except for provisions relating to the transfer restriction and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the New Notes. Oncor has agreed to use commercially reasonable efforts to cause this exchange offer to be completed within 315 days after the issue date of the New Notes, or if required, to use commercially reasonable efforts to have one or more shelf registration statements declared effective within the later of 180 days after such shelf registration statement filing obligation arises and 270 days after the issue date of the New Notes. If Oncor does not comply with this obligation (a registration default), the annual interest rate on the New Notes will increase by 0.50% per annum for the period during which the registration default continues, but not later than the second anniversary of the issue date of the New 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 New Notes.

Deed of Trust Amendment

Oncor’s secured indebtedness, including the 2040 Notes and New Notes described above and the revolving credit facility described in Note 3, are secured equally and ratably by a first priority lien on property acquired or constructed by Oncor for the transmission and distribution of electricity. The property is mortgaged under the Deed of Trust. The Deed of Trust permits Oncor to secure other indebtedness with the lien of the Deed of Trust up to the aggregate of (i) the amount of available bond credits, and (ii) 85% of the fair value of certain property additions that could be certified to the Deed of Trust collateral agent. At September 30, 2010, the available bond credits were approximately $1.338 billion and the amount of additional potential indebtedness that could be secured by property additions, subject to a certification process, was $1.040 billion.

On September 3, 2010, Oncor amended the Deed of Trust. Prior to the amendment, the Deed of Trust provided that Oncor could release the lien upon the satisfaction and discharge of all of its obligations under its revolving credit facility. The amendment to the Deed of Trust eliminated this ability to release the lien prior to the payment and performance in full of all obligations secured by the lien of the Deed of Trust.

F-206

Fair Value of Long-Term Debt

The estimated fair value of long-term debt (including current maturities) totaled $6.455 billion and $5.644 billion at September 30, 2010 and December 31, 2009, respectively, and the carrying amount totaled $5.506 billion and $5.104 billion, respectively. The fair value is estimated at the lesser of either the call price or the market value as determined by quoted market prices.

5.    COMMITMENTS AND CONTINGENCIES

Guarantees

Oncor has entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions.

Oncor is the lessee under various operating leases that obligate it to guarantee the residual values of the leased assets. At September 30, 2010, both the aggregate maximum amount of residual values guaranteed and the estimated residual recoveries totaled approximately $2 million. These leased assets consist primarily of vehicles used in distribution activities. The average life of the residual value guarantees under the lease portfolio is approximately three years.

In June 2010, Oncor, for the purpose of obtaining greater access to materials, guaranteed the repayment of borrowings under a nonaffiliated party’s $20 million credit facility maturing on June 7, 2011. The nonaffiliated party’s borrowings under the credit facility are limited to inventory produced solely to satisfy the terms of a contract with Oncor. Oncor would be entitled to the related inventory upon repayment of the credit facility (or payment to nonaffiliated party). At September 30, 2010, the nonaffiliated party had borrowings of $1.8 million under the facility.

Legal Proceedings

Oncor Holdings is involved in various 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 upon its financial position, results of operations or cash flows.

6.    MEMBERSHIP INTERESTS

At September 30, 2010, Oncor’s ownership was as follows: 80.03% held by Oncor Holdings, 19.75% held by Texas Transmission and 0.22% held indirectly by certain members of Oncor’s management and board of directors.

Cash Distributions

During 2010, Oncor Holdings’ board of directors declared, and Oncor Holdings paid/will pay, the following cash distributions to EFIH:

Declaration Date	Payment Date	Amount
October 27, 2010	November 1, 2010	$	28
July 28, 2010	August 3, 2010	$	54
May 5, 2010	May 6, 2010	$	57
February 11, 2010	February 19, 2010	$	30

While there are no direct restrictions on Oncor Holdings’ ability to distribute its net income that are currently material, substantially all of Oncor Holdings’ net income is derived from Oncor. The boards of directors of each of Oncor and Oncor Holdings, which are composed of a majority of independent directors, can withhold distributions to the extent the boards determine that it is necessary to retain such amounts to meet expected future requirements of Oncor and/or Oncor Holdings.

Oncor’s distributions are limited to Oncor’s cumulative net income and may not be made except to the extent Oncor maintains a required regulatory capital structure, as discussed below. At September 30, 2010, $35 million was eligible to be distributed to Oncor’s members after taking into account these restrictions.

F-207

For the period beginning October 11, 2007 and ending December 31, 2012, distributions paid by Oncor (other than distributions of the proceeds of any issuance of limited liability company units) are limited by the Limited Liability Company Agreement and a stipulation agreement with the PUCT (see Note 4 to the 2009 Audited Financial Statements) to an amount not to exceed Oncor’s cumulative net income determined in accordance with US GAAP, as adjusted by applicable orders of the PUCT. Such adjustments include deducting the $72 million ($46 million after tax) one-time refund to customers in September 2008, net accretion of fair value adjustments resulting from purchase accounting and funds spent as part of the $100 million commitment for additional demand-side management or other energy efficiency initiatives of which $35 million ($23 million after tax) has been spent through September 30, 2010, and removing the effect of the $860 million goodwill impairment charge from fourth quarter 2008 net income available for distribution. The goodwill impairment charge and refund are described in the 2009 Audited Financial Statements. As a result, $9 million of Oncor’s $149 million net income earned in the three months ended September 30, 2010, was restricted from being used to make distributions of membership interests under the cumulative net income restriction.

Distributions are further limited by Oncor’s required regulatory capital structure to 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. At September 30, 2010 and December 31, 2009, Oncor’s regulatory capitalization ratios were 59.7% debt and 40.3% equity and 58.1% debt and 41.9% equity, respectively. The PUCT has the authority to determine what types of debt and equity are included in a utility’s debt-to-equity ratio. For purposes of this ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. The debt calculation excludes transition bonds issued by Bondco. Equity is calculated as membership interests determined in accordance with GAAP, excluding the effects of accounting for the Merger (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization). Oncor is required to file a quarterly Earnings Monitor Report with the PUCT that sets forth its debt-to-equity ratio. This Earnings Monitor Report shall not be deemed a part of, or incorporated by reference into, this report. At September 30, 2010, $35 million of membership interests was available for distribution under the capital structure restriction of which approximately 80% relates to Oncor Holdings’ ownership interest.

Changes in Membership Interests

The following table presents the changes to membership interests during the nine months ended September 30, 2010:

	Capital Account			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Membership Interests
Balance at December 31, 2009	$	5,397		$	(2	)	$	1,363		$	6,758
Net income		240			—			61			301
Distributions paid to parent		(141	)		—			—			(141	)
Distributions to noncontrolling interests		—			—			(35	)		(35	)
Capital contributions (a)		31			—			—			31
Change related to future tax distributions from Oncor		—			—			53			53
Other		—			—			—			—
Balance at September 30, 2010	$	5,527		$	(2	)	$	1,442		$	6,967

(a) Reflects noncash settlement of certain income taxes payable arising as a result of the sale of noncontrolling interests in Oncor.

F-208

The following table presents the changes to membership interests during the nine months ended September 30, 2009:

	Capital Account			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Membership Interests
Balance at December 31, 2008	$	5,448		$	(2	)	$	1,355		$	6,801
Net income		217			—			54			271
Distributions paid to parent		(117	)		—			—			(117	)
Distributions to noncontrolling interests		—			—			(32	)		(32	)
Capital contributions (a)		22			—			—			22
Other		—			—			1			1
Balance at September 30, 2009	$	5,570		$	(2	)	$	1,378		$	6,946

(a) Reflects noncash settlement of certain income taxes payable arising as a result of the sale of noncontrolling interests in Oncor.

7. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) COSTS

Oncor is a participating employer in the EFH Retirement Plan, a defined benefit pension plan sponsored by EFH Corp., and also participates with EFH Corp. and certain other affiliated subsidiaries of EFH Corp. to offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees.

In November 2009, Oncor entered into a supplemental retirement plan that became effective January 1, 2010 (the Oncor Plan), and on January 1, 2010, Oncor ceased participating in the EFH Corp. supplemental retirement plan. The Oncor Plan covers certain employees whose retirement benefits cannot be fully earned under the qualified EFH Retirement Plan. The Oncor Plan is substantially similar to the EFH Corp. supplemental retirement plan, except that Oncor acts as sponsor of the Oncor Plan. At inception, the projected benefit obligation of the Oncor Plan was $32 million, which was 100% funded. Oncor recognized $1 million and $3 million in net pension costs related to the Oncor Plan, primarily composed of interest costs, for the three and nine months ended September 30, 2010, respectively.

The net direct and allocated pension and OPEB costs applicable to Oncor for all of these plans for the three and nine months ended September 30, 2010 and 2009 are comprised of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Amounts recognized as expense	$	9	$	5	$	27	$	14
Amounts deferred principally as a regulatory asset or property		24		18		68		51
Net pension and OPEB costs	$	33	$	23	$	95	$	65

The discount rate reflected in net pension and OPEB costs in 2010 is 5.90%. The expected rates of return on pension and OPEB plan assets reflected in the 2010 cost amounts are 8.0% and 7.6%, respectively.

Oncor made cash contributions to EFH Corp.’s pension and OPEB plans and the Oncor Plan of $27 million, $13 million and $2 million, respectively, during the nine months ended September 30, 2010.

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8. RELATED–PARTY TRANSACTIONS

The following represent significant related-party transactions of Oncor Holdings:

• Oncor records revenue from TCEH, principally for electricity delivery fees, which totaled $317 million and $308 million for the three months ended September 30, 2010 and 2009, respectively, and $839 million and $783 million for the nine months ended September 30, 2010 and 2009, respectively. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheets at September 30, 2010 and December 31, 2009 reflect receivables from TCEH totaling $182 million and $151 million, respectively, primarily related to these electricity delivery fees.

• Oncor records interest income from TCEH with respect to Oncor’s generation-related regulatory assets, which have been securitized through the issuance of transition bonds by Oncor’s bankruptcy-remote financing subsidiary. The interest income serves to offset Oncor’s interest expense on the transition bonds. This interest income totaled $9 million and $10 million for the three months ended September 30, 2010 and 2009, respectively, and $28 million and $32 million for the nine months ended September 30, 2010 and 2009, respectively.

• Incremental amounts payable by Oncor related to income taxes as a result of delivery fee surcharges to its customers related to transition bonds are reimbursed by TCEH. Oncor Holding’s financial statements reflect a note receivable from TCEH to Oncor of $227 million ($38 million reported as current in trade accounts and other receivables from affiliates) at September 30, 2010 and $254 million ($37 million reported as current in trade accounts and other receivables from affiliates) at December 31, 2009 related to these income taxes.

• An EFH Corp. subsidiary charges Oncor for certain administrative services at cost. These costs, which are reported in operation and maintenance expenses, totaled $9 million and $6 million for the three months ended September 30, 2010 and 2009, respectively, and $27 million and $19 million for the nine months ended September 30, 2010 and 2009, respectively.

• Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility (reported on TCEH’s balance sheet) is funded by a delivery fee surcharge collected from REPs by Oncor and remitted to TCEH. These trust fund assets are established with the intent to be sufficient to fund the estimated decommissioning liability (also reported on TCEH’s balance sheet). Income and expenses associated with the trust fund and the decommissioning liability recorded by TCEH are offset by a net change in the Oncor and TCEH intercompany receivable/payable, which in turn results in a change in Oncor’s reported net regulatory asset/liability. A regulatory liability represents the excess of the trust fund balance over the net decommissioning liability, and a regulatory asset represents the excess of the net decommissioning liability over the trust fund balance.

The change from a regulatory asset of $85 million at December 31, 2009 to a regulatory liability of $183 million at September 30, 2010 reflects a new decommissioning cost estimate completed in the second quarter 2010. In accordance with regulatory requirements, a new cost estimate is completed every five years. The change reflected lower cost escalation assumptions as compared to the previous estimate, resulting in a decline in the estimated decommissioning liability (see Note 2).

• EFH Corp. files a consolidated federal income tax return and allocates income tax liabilities to Oncor Holdings under a tax sharing agreement substantially as if Oncor Holdings was filing its own income tax returns. Oncor Holdings’ results are included in the consolidated Texas state margin tax return filed by EFH Corp. Oncor Holdings’ amount receivable from EFH Corp. related to income taxes under the tax sharing agreement totaled $59 million at September 30, 2010, and amount payable to EFH Corp. related to income taxes totaled $5 million at December 31, 2009. In the nine months ended September 30, 2010, Oncor made payments in lieu of federal income taxes totaling $107 million to EFH Corp., and $21 million to noncontrolling interests.

• Oncor held cash collateral of $4 million and $15 million at September 30, 2010 and December 31, 2009, respectively, from TCEH related to interconnection agreements for generation units being developed by TCEH. The collateral is reported in the balance sheet in other current liabilities. In January 2010, Oncor returned $11 million of the collateral and paid $1 million in accrued interest related to these units.

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• Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, at September 30, 2010 and December 31, 2009, TCEH had posted letters of credit in the amount of $14 million and $15 million, respectively, for Oncor’s benefit.

• At the closing of the Merger in 2007, Oncor entered into its current $2 billion revolving credit facility with a syndicate of financial institutions and other lenders. The syndicate includes affiliates of GS Capital Partners (a member of the Sponsor Group). Affiliates of GS Capital Partners have from time-to-time engaged in commercial transactions with Oncor in the normal course of business.

• Affiliates of the Sponsor Group have, from time-to-time, performed, and may in the future perform, various financial advisory, dealer, commercial banking and investment banking services for Oncor and certain of its affiliates for which they have received or will receive customary fees and expenses.

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

See Notes 6 and 7 for information regarding distributions to EFIH and the allocation of EFH Corp.’s pension and OPEB costs to Oncor, respectively.

9. SUPPLEMENTARY FINANCIAL INFORMATION

Consolidation of Variable Interest Entities

Oncor Holdings adopted amended accounting standards on January 1, 2010 that require consolidation of a variable interest entity if Oncor Holdings has the power to direct the significant activities of the VIE and the right or obligation to absorb profit and loss from the VIE. A VIE is an entity with which Oncor Holdings has a relationship or arrangement that indicates some level of control over the entity or results in economic risks to Oncor Holdings that are typically borne by an equity owner. The adoption of this accounting guidance did not result in Oncor Holdings consolidating any additional VIEs.

Oncor is the primary beneficiary and consolidates a wholly-owned VIE, Bondco, which was organized for the limited purpose of issuing securitization (transition) bonds and purchasing and owning transition property acquired from Oncor, which is pledged as collateral to secure the bonds. Oncor acts as the servicer for this entity to collect securitization transition charges authorized by the PUCT. These funds are remitted to the trustee and used for interest and principal payments on the transition bonds and related costs.

The assets and liabilities of Bondco are presented separately on the face of Oncor Holdings’ Condensed Consolidated Balance Sheet because the assets are restricted and can only be used to settle the obligations of Bondco, and Bondco’s creditors do not have any recourse to the general credit or assets of Oncor Holdings or any of its subsidiaries.

Oncor Holdings’ maximum exposure does not exceed its equity investment in Bondco, which was $16 million at both September 30, 2010 and December 31, 2009. Oncor Holdings did not provide any financial support to Bondco during the nine months ended September 30, 2010 and 2009.

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Other Income and Deductions

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Other income:
Accretion of adjustment (discount) to regulatory assets due to purchase accounting	$	8	$	10	$	26	$	30
Other		—		—		2		—
Total other income	$	8	$	10	$	28	$	30
Other deductions:
Professional fees	$	—	$	2	$	2	$	7
Costs related to 2006 cities rate settlement		—		1		—		2
Other		1		2		3		5
Total other deductions	$	1	$	5	$	5	$	14

Major Customers

Distribution revenues from TCEH represented 38% and 40% of total operating revenues for the three months ended September 30, 2010 and 2009, respectively, and 38% of total operating revenues for both the nine months ended September 30, 2010 and 2009. Revenues from subsidiaries of one nonaffiliated REP collectively represented 12% and 13% of total operating revenues for the three months ended September 30, 2010 and 2009, respectively, and 12% and 14% of total operating revenues for the nine months ended September 30, 2010 and 2009, respectively. No other customer represented 10% or more of total operating revenues.

Interest Expense and Related Charges

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010		2009			2010			2009
Accrued interest	$	84	$	84		$	253		$	254
Amortization of fair value debt discounts resulting from purchase accounting		1		—			2			2
Amortization of debt issuance costs and discounts		2		2			5			5
Allowance for funds used during construction — capitalized interest portion		—		(1	)		(1	)		(3	)
Total interest expense and related charges	$	87	$	85		$	259		$	258

Trade Accounts Receivable

	At September  30, 2010			At December 31, 2009
Gross trade accounts receivable	$	469		$	395
Trade accounts receivable from TCEH		(176	)		(150	)
Allowance for uncollectible accounts		(2	)		(2	)
Trade accounts receivable from nonaffiliates — net	$	291		$	243

Gross trade accounts receivable at both September 30, 2010 and December 31, 2009 included unbilled revenues of $141 million.

Investments

	September 30, 2010		December 31, 2009
Assets related to employee benefit plans, including employee savings programs, net of distributions	$	72	$	67
Investments in unconsolidated affiliates		1		3
Land		3		2
Total investments	$	76	$	72

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Property, Plant and Equipment

At September 30, 2010 and December 31, 2009, property, plant and equipment of $9.5 billion and $9.2 billion, respectively, is stated net of accumulated depreciation and amortization of $4.6 billion and $4.4 billion, respectively.

Identifiable Intangible Assets

Intangible assets other than goodwill reported in the balance sheet are comprised of the following:

	At September 30, 2010						At December 31, 2009
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Intangible assets subject to amortization included in property, plant and equipment:
Land easements	$	201	$	73	$	128	$	188	$	72	$	116
Capitalized software		337		131		206		240		104		136
Total	$	538	$	204	$	334	$	428	$	176	$	252

Aggregate amortization expense for intangible assets totaled $10 million and $9 million for the three months ended September 30, 2010 and 2009, respectively, and $28 million and $21 million for the nine months ended September 30, 2010 and 2009, respectively. The estimated aggregate amortization expense for each of the next five fiscal years from December 31, 2009 is as follows:

Year	Amortization Expense
2010	$	39
2011		41
2012		32
2013		32
2014		32

At both September 30, 2010 and December 31, 2009, goodwill of $4.1 billion was reported on the balance sheet. None of this goodwill balance is being deducted for tax purposes.

Exit Liabilities

Liabilities related to the termination and transition of outsourcing arrangements were accrued in purchase accounting for exit activities resulting from the Merger (see Note 2 to the 2009 Audited Financial Statements). Oncor settled the remaining exit liabilities totaling $2 million during the six months ended June 30, 2010.

Other Noncurrent Liabilities and Deferred Credits

The other noncurrent liabilities and deferred credits balance consists of the following:

	September 30, 2010		December 31, 2009
Retirement plan and other employee benefits	$	1,355	$	1,343
Liabilities related to subsidiary tax sharing agreement		297		321
Uncertain tax positions (including accrued interest)		74		91
Nuclear decommissioning cost under-recovery (a)		—		85
Other		49		39
Total other noncurrent liabilities and deferred credits	$	1,775	$	1,879

(a) Represents intercompany payable to TCEH offset in Oncor’s net reported regulatory asset/liability. See Note 2.

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Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2010			2009
Cash payments:
Interest paid	$	284		$	283
Capitalized interest		(1	)		(3	)
Interest paid (net of amounts capitalized)		283			280
Income taxes		128			28
Noncash investing and financing activities:
Noncash construction expenditures (a)		58			56
Capital contributions related to settlement of certain income taxes payable (see Note 6)		31			22

(a) Represents end-of-period accruals.

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ENERGY FUTURE HOLDINGS CORP.

Offer to Exchange

$1,060,757,000 aggregate principal amount of its 10.000% Senior Secured Notes due 2020, which have been registered under

the Securities Act of 1933, as amended, for any and all of its outstanding 10.000% Senior Secured Notes due 2020

Until the date that is 180 days from the date of this prospectus, all dealers that effect transactions in these

securities, whether or not participating in the exchange offer, 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.