As filed with the Securities and Exchange Commission on January 30, 2009

Registration No. 333-

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Energy Future Competitive Holdings Company

(Exact name of registrant parent guarantor as specified in its charter)

Texas

4911

75-1837355

(State or other jurisdiction

of incorporation)

(Primary Standard Industrial Classification Code Number)

(I.R.S. Employer

Identification Number)

Texas Competitive Electric Holdings Company LLC

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

Delaware

4911

75-2967817

(State or other jurisdiction

of incorporation)

(Primary Standard Industrial Classification Code Number)

(I.R.S. Employer

Identification Number)

TCEH Finance, Inc.

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

Delaware

4911

26-2137715

(State or other jurisdiction

of incorporation)

(Primary Standard Industrial Classification Code Number)

(I.R.S. Employer

Identification Number)

SEE TABLE OF ADDITIONAL REGISTRANTS

1601 Bryan Street

Dallas, Texas 75201-3411

(214) 812-4600

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

Andrew M. Wright

EFH Corporate Services Company

Vice President and Associate General Counsel

1601 Bryan Street

Dallas, Texas 75201-3411

(214) 812-4600

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

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

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. x

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

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

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

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


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

CALCULATION OF REGISTRATION FEE



Title of Each Class of Securities to be Registered	Amount to be Registered	Proposed Maximum Offering Price Per Note	Proposed Maximum Aggregate Offering Price(1)	Amount of Registration Fee(1)
10.25% Senior Notes due 2015	(1)	(1)	(1)	(1)
10.25% Senior Notes due 2015, Series B	(1)	(1)	(1)	(1)
10.50%/11.25% Senior Toggle Notes due 2016	(1)	(1)	(1)	(1)
Guarantees of 10.25% Senior Notes due 2015(2)	(1)(3)	(1)(3)	(1)(3)	(1)(3)
Guarantees of 10.25% Senior Notes due 2015, Series B(2)	(1)(3)	(1)(3)	(1)(3)	(1)(3)
Guarantees of 10.50%/11.25% Senior Toggle Notes due 2016(2)	(1)(3)	(1)(3)	(1)(3)	(1)(3)

(1)

An indeterminate amount of securities are being registered hereby to be offered solely for market-making purposes by specified affiliates of the registrants. Pursuant to Rule 457(q) under the Securities Act of 1933, as amended (the “Securities Act”), no filing fee is required with respect to such securities.

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

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

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

Table of Additional Registrant Guarantors


Exact Name of Registrant Guarantor as Specified in its Charter (or Other Organizational Document)	State or Other Jurisdiction of Incorporation or Organization	I.R.S. Employer Identification Number	Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant Guarantor’s Principal Executive Offices
Big Brown 3 Power Company LLC	Texas	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Big Brown Lignite Company LLC	Texas	52-2364247	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Big Brown Power Company LLC	Texas	75-2967823	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Collin Power Company LLC	Delaware	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Decordova Power Company LLC	Texas	75-2967797	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
DFW Midstream Services LLC	Texas	75-2967817	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Generation MT Company LLC	Delaware	75-2967818	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Generation SVC Company	Texas	45-0470622	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Lake Creek 3 Power Company LLC	Texas	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Luminant Big Brown Mining Company LLC	Texas	75-3006803	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Luminant Energy Company LLC	Texas	26-0022234	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Luminant Energy Services Company	Delaware	74-3195086	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Luminant Energy Trading California Company	Texas	75-2723853	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Luminant ET Services Company	Texas	75-2967835	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Luminant Generation Company LLC	Texas	75-2967820	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Luminant Holding Company LLC	Delaware	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600


Exact Name of Registrant Guarantor as Specified in its Charter (or Other Organizational Document)	State or Other Jurisdiction of Incorporation or Organization	I.R.S. Employer Identification Number	Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant Guarantor’s Principal Executive Offices
Luminant Mineral Development Company LLC	Texas	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Luminant Mining Company LLC	Texas	75-2967821	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Luminant Mining Services Company	Delaware	74-3195084	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Luminant Power Services Company	Delaware	74-3195081	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Luminant Renewables Company LLC	Texas	20-3007585	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Martin Lake 4 Power Company LLC	Texas	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Monticello 4 Power Company LLC	Texas	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Morgan Creek 7 Power Company LLC	Texas	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
NCA Resources Development Company LLC	Texas	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Oak Grove Management Company LLC	Delaware	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Oak Grove Mining Company LLC	Texas	20-8516181	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Oak Grove Power Company LLC	Texas	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Sandow Power Company LLC	Texas	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Tradinghouse 3 & 4 Power Company LLC	Texas	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600


Exact Name of Registrant Guarantor as Specified in its Charter (or Other Organizational Document)	State or Other Jurisdiction of Incorporation or Organization	I.R.S. Employer Identification Number	Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant Guarantor’s Principal Executive Offices
Tradinghouse Power Company LLC	Texas	75-2967804	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
TXU Chilled Water Solutions Company	Texas	75-2808730	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
TXU Energy Retail Company LLC	Texas	26-0494257	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
TXU Energy Retail Management Company LLC	Delaware	26-0022145	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
TXU Energy Solutions Company LLC	Texas	26-0022193	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
TXU Retail Services Company	Delaware	20-5872839	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
TXU SEM Company	Texas	75-2795541	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
TXU SESCO Company LLC	Texas	82-0539333	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
TXU SESCO Energy Services Company	Texas	75-2959527	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Valley NG Power Company LLC	Texas	75-2967820	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Valley Power Company LLC	Texas	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600
Wichita/Victory Ave., LLC	Texas	54-2127719	1601 Bryan Street Dallas, Texas 75201-3411 (214) 812-4600

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

SUBJECT TO COMPLETION, DATED JANUARY 30, 2009

PROSPECTUS

TEXAS COMPETITIVE ELECTRIC HOLDINGS COMPANY LLC

TCEH FINANCE, INC.

$3,000,000,000 10.25% Senior Notes due 2015

$2,000,000,000 10.25% Senior Notes due 2015, Series B

$1,750,000,000 10.50%/11.25% Senior Toggle Notes due 2016

Interest on the 10.25% Senior Notes due 2015 (the “initial cash-pay notes”), the 10.25% Senior Notes due 2015, Series B (the “Series B cash-pay notes,” and together with the initial cash-pay notes, the “cash-pay notes”) and the 10.50%/11.25% Senior Toggle Notes due 2016 (the “toggle notes,” and together with the cash-pay notes, the “notes”) is payable on May 1 and November 1 of each year. The cash-pay notes accrue interest at the rate of 10.25% per annum. Until November 1, 2012, Texas Competitive Electric Holdings Company LLC and TCEH Finance, Inc. (together, the “Issuer”) may elect to pay interest on the toggle notes in cash, by increasing the principal amount of the toggle notes or issuing new toggle notes (“PIK interest”) for the entire amount of the interest payment or by paying interest on half of the principal amount of the toggle notes in cash and half in PIK interest. The toggle notes accrue cash interest at a rate of 10.50% per annum and PIK interest at a rate of 11.25% per annum. If the Issuer elects to pay any PIK interest, the Issuer will increase the principal amount of the toggle notes or issue new toggle notes in an amount equal to the amount of PIK interest for the applicable interest payment period (rounded up to the nearest $1,000) to holders of the toggle notes on the relevant record date. The toggle notes are treated as having been issued with original issue discount for U.S. federal income tax purposes. The cash-pay notes will mature on November 1, 2015 and the toggle notes will mature on November 1, 2016.

The Issuer may redeem any of the cash-pay notes beginning on November 1, 2011 at the redemption prices set forth in this prospectus. The Issuer may also redeem any of the cash-pay notes at any time prior to November 1, 2011 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. The Issuer may redeem any of the toggle notes beginning on November 1, 2012 at the redemption prices set forth in this prospectus. The Issuer may also redeem any of the toggle notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. In addition, before November 1, 2010, the Issuer may redeem up to 35% of the aggregate principal amount of the notes using the proceeds from certain equity offerings at the redemption price set forth in this prospectus.

The notes are unsecured and rank equally with any unsecured senior indebtedness of the Issuer. The notes are fully and unconditionally guaranteed on a senior unsecured basis by the Issuer’s direct parent, Energy Future Competitive Holdings Company, and by each subsidiary that guarantees the Issuer’s senior secured credit facilities (as described herein). These guarantees are unsecured and rank equally with all existing and future unsecured senior obligations of each guarantor and are effectively subordinated to existing and future secured debt of such guarantor to the extent of the assets securing that indebtedness. Energy Future Holdings Corp., the indirect parent of the Issuer, does not guarantee the notes.

For a more detailed description of the notes, see “Description of the Notes” beginning on page 175.

See “Risk Factors” beginning on page 18 for a discussion of certain risks that you should consider before investing in the notes.

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

This prospectus has been prepared for and may be used by Goldman, Sachs & Co. (the “Market Maker”) and affiliates of the Market Maker in connection with offers and sales of the notes related to market-making transactions in the notes in the secondary market effected from time to time. The Market Maker and the affiliates of the Market Maker may act as principal or agent in such transactions, including as agent for the counterparty when acting as principal or as agent for both counterparties, and may receive compensation in the form of discounts and commissions, including from both counterparties, when it acts as agent for both. Sales of notes pursuant to this prospectus will be made at prevailing market prices at the time of sale, at prices related thereto or at negotiated prices. The Issuer will not receive any proceeds from such sales.

The date of this prospectus is , 2009.

You should rely only on the information contained in this prospectus. We have not, and the Market Maker or its affiliates have not, authorized anyone to provide you with different information. This prospectus may be used only for the purposes for which it has been published, and no person has been authorized to give any information not contained herein. If you receive any other information, you should not rely on it. 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 the registration statement of which this prospectus is a part 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 represent the parties’ risk allocation in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes or may no longer continue to be true as of any given date. No offer of these securities is being made in any state where any such offer is prohibited.

TABLE OF CONTENTS


		Page
Prospectus Summary		1
Risk Factors		18
Forward-Looking Statements		36
Industry and Market Information		37
The Transactions		38
Use of Proceeds		41
Capitalization		41
Energy Future Competitive Holdings Company and Subsidiaries Unaudited Pro Forma Condensed Statement of Consolidated Income (Loss)		42
Energy Future Competitive Holdings Company and Subsidiaries Selected Historical Consolidated Financial Data		43
Energy Future Competitive Holdings Company and Subsidiaries Notes to Unaudited Pro Forma Condensed Statement of Consolidated Income (Loss)		44
Energy Future Competitive Holdings Company and Subsidiaries Selected Historical Consolidated Financial Data		47
Management’s Discussion and Analysis of Financial Condition and Results of Operations		52
TCEH’s Businesses		112
Regulation and Rates		125
Management		127
Executive Compensation		131
Director Compensation		171
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		172
Description of the Notes		175
Book Entry Settlement and Clearance		241
Certain U.S. Federal Income Tax Consequences		245
Certain ERISA Considerations		254
Plan of Distribution		256
Legal Matters		257
Experts		257
Available Information		257
Glossary		259
Index to Consolidated Financial Statements

PROSPECTUS SUMMARY

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

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

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

Unless the context otherwise requires or as otherwise indicated, references in this prospectus to “EFC Holdings” refer to Energy Future Competitive Holdings Company and not to any of its subsidiaries. References to “we,” “our” and “us” refer to Energy Future Competitive Holdings Company and its consolidated subsidiaries. References to the “Issuer” collectively refer to Texas Competitive Electric Holdings Company LLC (“TCEH”) and TCEH Finance, Inc. (“TCEH Finance”), the co-issuers of the notes. See “Glossary” for other defined terms.

TCEH Businesses and Strategy

TCEH is a Dallas-based holding company for businesses engaged in competitive electricity market activities largely in Texas, including Luminant, which is engaged in electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases and commodity risk management and trading activities, and TXU Energy, which is engaged in retail electricity sales. TCEH is a wholly-owned subsidiary of EFC Holdings, which is a wholly-owned subsidiary of EFH Corp. While TCEH is a wholly-owned subsidiary of EFH Corp. and EFC Holdings, TCEH is a separate legal entity from EFH Corp. and EFC Holdings and all of their other affiliates with its own assets and liabilities.

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

At September 30, 2008, we had approximately 4,200 full-time employees, including approximately 2,000 employees under collective bargaining agreements.

TCEH’s Market

TCEH operates primarily within the ERCOT market, which represents approximately 85% of electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the system operator of the interconnected transmission grid for those systems. ERCOT’s membership consists of approximately 250 members, including electric cooperatives, municipal power agencies, investor-owned generators, power marketers, transmission service providers, distribution service providers, REPs and consumers.

The ERCOT market represents approximately 75% of the geographical area of Texas, but excludes El Paso, a large part of the Texas Panhandle and two small areas in the eastern part of the state. From 1996 through 2006, peak hourly demand in the ERCOT market grew at a compound annual rate of 2.8%, compared to a compound annual rate of growth of 2.5% for the entire U.S. over the same period. For 2007, hourly demand peaked at 62,188 MW. The ERCOT market has limited interconnections to other markets in the U.S., which currently limits potential imports into and exports out of the ERCOT market to 1,106 MW of generation capacity (or approximately 2% of peak demand). In addition, wholesale transactions within the ERCOT market are not subject to regulation by the U.S. Federal Energy Regulatory Commission (“FERC”).

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

Natural gas-fueled generation is the predominant electricity capacity resource in the ERCOT market and accounted for approximately 46% of the electricity produced in the ERCOT market in 2007. Because of the significant natural gas-fueled capacity and the ability of such plants to more readily increase or decrease production when compared to baseload generation, marginal demand for electricity is usually met by natural gas-fueled plants. ERCOT’s October 1, 2005 report titled “Report on Existing and Potential Electric System Constraints and Needs” found that natural gas-fueled plants set the market price more than 90% of the time in the ERCOT market. As a result, wholesale electricity prices in ERCOT are highly correlated to natural gas prices.

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

The ERCOT market operates under reliability standards set by the North American Electric Reliability Corporation (“NERC”). The PUCT has primary jurisdiction over the ERCOT market to ensure adequacy and reliability of power supply across Texas’s main interconnected transmission grid. The ERCOT independent system operator is responsible for maintaining reliable operations of the bulk electricity supply system in the ERCOT market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike certain other regional power markets, the ERCOT market is not a centrally dispatched power pool, and the ERCOT independent system operator does not procure energy on behalf of its members, except to the extent that it acquires ancillary services as agent for market participants. Members who sell and purchase power are responsible for contracting sales and purchases of power with other members through bilateral transactions. The ERCOT independent system operator also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.

TCEH’s Strategies

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

•

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

•

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

Other elements of TCEH’s strategy include:

•

Increase value from existing businesses. TCEH’s strategy focuses on striving for top quartile or better performance across its operations in terms of reliability, cost and customer service. TCEH will continue to focus on upgrading four critical skill sets: operational excellence across each business; market leadership and customer focus; a systematic risk/return mindset applied to all key decisions; and rigorous performance management targeting industry-leading performance standards for productivity, reliability and customer service. An example of how TCEH implements these principles is a program called the “Luminant Operating System,” which is a program to drive ongoing productivity improvements in Luminant’s operations through application of lean operating techniques and deployment of a high-performance industrial culture.

•

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

•

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

•

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

•

Reduce the volatility of cash flows through a commodity risk management strategy. A key component of TCEH’s risk management strategy is its plan to hedge approximately 80% of the natural gas price risk exposure of Luminant’s baseload generation output on a rolling five-year basis. The strong historical correlation between natural gas prices and wholesale electricity prices in the ERCOT market combined with the significant liquidity in certain natural gas markets provides an opportunity for management of TCEH’s exposure to natural gas prices. As of October 24, 2008, approximately 2.1 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 280,000 GWh at an assumed 7.5 MMBtu/MWh market heat rate) have been effectively sold forward by TCEH’s subsidiaries over the period from 2008 to 2014, at average annual prices ranging from $7.20 per MMBtu to $8.35 per MMBtu. Taking into consideration the estimated portfolio impacts of TCEH’s retail electricity business, these natural gas hedging transactions result in TCEH having effectively hedged approximately 77% of its expected baseload generation natural gas price exposure (on an average basis for 2008 through 2014). Certain of the hedging transactions are directly secured with a first-lien interest in TCEH’s assets, which eliminates liquidity requirements because no cash or letter of

credit posting is required. In addition, the TCEH Commodity Collateral Posting Facility, which is also secured by a first-lien interest in TCEH’s assets, supports the margin requirements for a significant portion of the remaining hedging transactions. Consequently, as of September 30, 2008, more than 95% of the hedging transactions were secured or supported by first-lien interests in TCEH’s assets and result in no direct liquidity exposure.

•

Pursue new environmental initiatives. TCEH is committed to continue to operate in compliance with all environmental laws, rules and regulations and to reduce its impact on the environment. EFH Corp. has formed a Sustainable Energy Advisory Board that advises in our pursuit of technology development opportunities that reduce our impact on the environment while balancing the need to address the energy requirements of Texas. EFH Corp.’s Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, customers, economic development in Texas and technology/reliability standards. In addition, TCEH is focused on and is pursuing opportunities to reduce emissions from its existing and planned new lignite/coal-fueled generation units in the ERCOT market. Luminant has voluntarily committed to reduce emissions of mercury, nitrogen oxide (NO_X”) and sulfur dioxide (“SO₂”) at its existing units, so that the total of those emissions from both existing and new lignite/coal-fueled units is 20% below 2005 levels. TCEH expects Luminant to make these reductions through a combination of investment in new emission control equipment, new coal cleaning technologies and optimizing fuel blends. TCEH also expect such investments to provide economic benefits by reducing future costs associated with complying with environmental emissions standards. TCEH expects TXU Energy will invest $100 million over a five year period beginning in 2008 in programs designed to encourage customer electricity demand efficiencies.

Recent Developments

Notice of Termination of Joint Venture Outsourcing Arrangements

On December 19, 2008, EFH Corp. and TCEH executed a Separation Agreement with Capgemini Energy LP (“Capgemini”), Capgemini America, Inc. and Capgemini North America, Inc. (collectively, “CgE”). The Separation Agreement principally provides for (i) notice of termination of the Master Framework Agreement, dated as of May 17, 2004, as amended, between Capgemini and TCEH and the related service agreements under the Master Framework Agreement and (ii) termination of the joint venture arrangements between EFH Corp. (and its applicable subsidiaries) and CgE.

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

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

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

•

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

•

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

•

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

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

Notice of Resignation of Executive Officer

On January 12, 2009, Michael T. McCall, the Chief Operating Officer of Luminant, gave notice that he would resign effective January 31, 2009 to pursue other personal and professional opportunities.

In connection with such resignation, on January 15, 2009, Mr. McCall, Luminant and EFH Corp. executed a Severance and Release Agreement. The material terms of such agreement are as follows:

•

Luminant will pay Mr. McCall a severance payment equal to approximately $2.1 million, largely representing the payment of (i) his 2008 annual incentive bonus and (ii) a previously granted retention bonus award, each of which is required to be paid under the terms of Mr. McCall’s existing employment agreement;

•

EFH Corp. will refund Mr. McCall $3 million in lieu of granting him shares of EFH Corp. stock otherwise due to him upon his resignation from Luminant; and

•

Mr. McCall will be entitled to receive a distribution of his vested awards or vested account balances under, and subject to the provisions of, certain of EFH Corp.’s employee benefit plans.

Impairment of Natural Gas-Fueled Generation Assets

In the fourth quarter of 2008, EFC Holdings initiated an evaluation of its natural gas-fueled generation fleet for impairment in accordance with the requirements of SFAS 144, which provides that long-lived assets should be tested for recovery whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The impairment test was triggered by the expectation that certain units will be retired and/or mothballed (idled) earlier than previously estimated. As a result of the evaluation, EFC Holdings expects to recognize a non-cash impairment charge of up to $200 million (pre-tax) in the fourth quarter of 2008.

Test for Goodwill Impairment

As required by accounting rules, EFC Holdings is in the process of performing its required annual goodwill impairment test. The valuation work has not been completed, but considering the recent dislocation in the

financial markets and the significant amount of EFC Holdings’ goodwill, the analyses could result in the recording of a material, non-cash impairment charge by EFC Holdings in the fourth quarter of 2008.

TCEH was formed in Texas in November 2001 and TCEH Finance, Inc. was incorporated in Delaware in September 2007. The Issuer’s principal executive offices currently are located at Energy Plaza, 1601 Bryan Street, Dallas, TX 75201-3411, and its telephone number is (214) 812-4600.

The Transactions

The Merger

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

EFH Corp.’s direct subsidiaries include EFC Holdings and Energy Future Intermediate Holding Company LLC (“Intermediate Holding”). EFC Holdings is the direct parent company of TCEH. Intermediate Holding is the parent of Oncor Electric Delivery Holdings Company LLC (“Oncor Holdings”), the holding company for EFH Corp.’s electricity distribution and transmission business, Oncor Electric Delivery Company LLC (“Oncor”).

EFH Corp. and Intermediate Holding and its subsidiaries, which includes Oncor, are not guarantors of the notes.

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

Equity Contributions

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

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

Debt Financing

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

•

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

(a)

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

(b)

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

(c)

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

(d)

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

(e)

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

•

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

In addition, EFC Holdings, a guarantor of the notes, guaranteed the $4.5 billion aggregate principal amount of senior unsecured interim loan facility of EFH Corp. (the “EFH Senior Interim Facility”), which was used to fund the Merger and related transactions.

In October 2007 and December 2007, the Issuer issued the notes. The proceeds from the offerings of the notes, along with cash on hand, were used by TCEH to repay in full the TCEH Senior Interim Facility.

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

We refer to the above, collectively, as the “Debt Financing.” See Note 16 to the 2007 year-end Financial Statements and Note 7 to the September 30, 2008 Financial Statements for a description of the material terms of each component of the Debt Financing.

Also, in connection with the Merger, EFH Corp.’s accounts receivable securitization program (the “Receivables Program”), pursuant to which we sell trade accounts receivable to TXU Receivables Company, EFH Corp.’s consolidated wholly-owned bankruptcy-remote direct subsidiary, which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions, was amended. In connection with the amendment, the special purpose entities established by the financial institutions requested that Oncor repurchase all of the receivables it had previously sold to TXU Receivables Company. Accordingly, Oncor repurchased its receivables.

On September 25, 2007, EFH Corp. commenced offers to purchase and consent solicitations with respect to $1.0 billion in aggregate principal amount of EFH Corp.’s outstanding 4.80% Series O Senior Notes due 2009, $250 million in aggregate principal amount of TCEH’s outstanding 6.125% Senior Notes due 2008 and $1.0 billion in aggregate principal amount of TCEH’s outstanding 7.000% Senior Notes due 2013 (collectively, the “Specified Notes”). On the closing date of the Merger, EFH Corp. purchased an aggregate of $996 million, $247 million and $995 million of the principal amount of these notes, respectively. In connection with the Merger, EFH Corp. and its consolidated subsidiaries redeemed and repaid an aggregate of approximately $5.5 billion of existing consolidated indebtedness (excluding indebtedness of Oncor), including debt that became payable upon the consummation of the Merger. We refer to the tender offers for the Specified Notes and the redemption and repayment of this outstanding indebtedness as the “Debt Repayment.”

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

Sources and Uses

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


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

Equity contributions(4)		8,300
Existing debt(8)		4,743

Total sources of funds	$	44,221	Total uses of funds	$	44,221

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

(a)

the $16.45 billion TCEH Initial Term Loan Facility;

(b)

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

(c)

the $2.7 billion TCEH Revolving Credit Facility;

(d)

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

(e)

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

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

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

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

(5)

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

(6)	Repayment of existing indebtedness consists of the Debt Repayment described above.

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

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

The Notes

The summary below describes the principal terms of the notes. Certain of the terms and conditions described below are subject to important limitations and exceptions. The “Description of the Notes” section of this prospectus contains more detailed descriptions of the terms and conditions of the notes.

Issuers

Texas Competitive Electric Holdings Company LLC and TCEH Finance, Inc.

Securities Offered

$6,750,000,000 aggregate principal amount of notes consisting of:

•

$3,000,000,000 initial cash-pay notes;

•

$2,000,000,000 Series B cash-pay notes; and

•

$1,750,000,000 toggle notes.

Each of the initial cash-pay notes, the Series B cash-pay notes and the toggle notes are a separate series of notes under the indenture but will be treated as a single class of securities under the indenture for amendments and waivers and for taking certain actions, except as otherwise stated herein.

Maturity Date

Cash-pay notes: November 1, 2015.

Toggle notes: November 1, 2016

Interest Rate

The cash-pay notes will accrue interest at the rate of 10.25% per annum.

Until November 1, 2012, the Issuer may elect to pay interest on the toggle notes, at the Issuer’s option:

•

entirely in cash;

•

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

•

50% in cash and 50% in PIK interest.

The toggle notes accrue cash interest at a rate of 10.50% per annum and PIK interest at a rate of 11.25% per annum.

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

Interest Payment Dates

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

Ranking

The notes are the Issuer’s senior unsecured obligations and:

•

rank senior in right of payment to any future subordinated indebtedness of the Issuer;

•

rank equally in right of payment with all of the Issuer’s existing and future senior unsecured indebtedness;

•

are structurally subordinated in right of payment to all existing and future indebtedness, preferred stock and other liabilities of the Issuer’s non-guarantor subsidiaries, including trade payables (other than indebtedness and liabilities owed to the Issuer or the Guarantors (as defined below)); and

•

rank effectively junior in right of payment to all existing and future senior secured indebtedness of the Issuer to the extent of the assets securing that indebtedness.

As of September 30, 2008, the notes would have ranked effectively junior to approximately $23.9 billion of the Issuer’s senior secured indebtedness, most of which would have been represented by its borrowings under the TCEH Senior Secured Facilities. As of September 30, 2008, TCEH had approximately $1.6 billion of additional available capacity under the TCEH Senior Secured Facilities (excluding amounts available under the TCEH Commodity Collateral Posting Facility).

Guarantees

The notes are unconditionally guaranteed by TCEH’s direct parent, EFC Holdings, and by each subsidiary that guarantees the TCEH Senior Secured Facilities (the “Guarantors”) on a senior unsecured basis. The guarantees rank equally with any unsecured senior indebtedness of the Guarantors and are effectively junior to all secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. As of September 30, 2008, the guarantees ranked effectively junior to approximately $24.0 billion principal amount of the Guarantors’ senior secured indebtedness, represented by their guarantees of the TCEH Senior Secured Credit Facilities, $293 million of other TCEH secured indebtedness and $112 million of senior secured indebtedness at EFC Holdings, the Parent Guarantor. The guarantee by EFC Holdings of the notes ranks equally with its guarantee of the $4.5 billion principal amount of EFH Corp. Notes. The guarantees are structurally junior to all indebtedness and other liabilities of the Issuer’s subsidiaries that do not guarantee the notes.

EFH Corp., our parent, does not guarantee the notes. In addition, none of the entities comprising EFH Corp.’s regulated electricity transmission and distribution business guarantee the notes. Those entities consist of Intermediate Holding, Oncor Holdings Company

LLC and Oncor and its bankruptcy remote financing subsidiary that was established solely to issue securitization bonds.

Security

None.

Optional Redemption

The Issuer may redeem any of the cash-pay notes beginning on November 1, 2011 at the redemption prices set forth in this prospectus. The Issuer may also redeem any of the cash-pay notes at any time prior to November 1, 2011 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. In addition, before November 1, 2010, the Issuer may redeem up to 35% of the aggregate principal amount of the cash-pay notes, using the proceeds from certain equity offerings at the redemption price set forth in this prospectus. See “Description of the Notes—Optional Redemption.”

The Issuer may redeem any of the toggle notes beginning on November 1, 2012 at the redemption prices set forth in this prospectus. The Issuer may also redeem any of the toggle notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. In addition, before November 1, 2010, the Issuer may redeem up to 35% of the aggregate principal amount of the toggle notes, using the proceeds from certain equity offerings at the redemption price set forth in this prospectus. See “Description of the Notes—Optional Redemption.”

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

Change of Control Offer

Upon the occurrence of a change of control, you will have the right, as a holder of the notes, to require the Issuer to repurchase some or all of your notes at 101% of their face amount, plus accrued and unpaid

interest to the repurchase date. See “Description of the Notes—Repurchase at the Option of Holders—Change of Control.”

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

•

the Issuer may not have enough funds at that time; or

•

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

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

Important Covenants

The indenture governing the notes contains covenants limiting the Issuer’s ability and the ability of its restricted subsidiaries to:

•

incur additional debt or issue some types of preferred shares;

•

pay dividends on or make other distributions in respect of TCEH’s capital stock or make other restricted payments;

•

make investments;

•

sell assets;

•

create liens on assets to secure debt;

•

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

•

enter into certain transactions with our affiliates; and

•

designate our subsidiaries as unrestricted subsidiaries.

These covenants are subject to a number of important limitations and exceptions. See “Description of the Notes.”

Voting

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

Original Issue Discount

The Issuer has the option to pay interest on the exchange toggle notes in cash interest or PIK interest for any interest payment period prior to November 1, 2012. For U.S. federal income tax purposes, the existence of this option means that none of the interest payments on the toggle notes are “qualified stated interest”. Consequently, the toggle notes are treated as having been issued with “original issue discount,” and U.S. holders (as defined under “Certain U.S. Federal Income Tax Consequences”) are required to include the original issue discount in gross income for U.S. federal income tax purposes on a constant yield to maturity basis, regardless of whether interest is paid currently in cash. In addition, because the “stated redemption price at

maturity” of the Series B cash-pay notes exceeds their issue price by more than the statutory de minimis threshold, the Series B cash-pay notes are treated as having been issued with original issue discount. Therefore, a U.S. holder of a Series B cash pay note is required to include such original issue discount in gross income as it accrues, in advance of the receipt of cash attributable to that income and regardless of the U.S. holder’s regular method of accounting for U.S. federal income tax purposes. For more information, see “Certain U.S. Federal Income Tax Consequences.”

Use of Proceeds

This prospectus may be delivered in connection with the resale of notes by the Market Maker and the affiliates of the Market Maker in market-making transactions in the notes in the secondary market. We will not receive any of the proceeds from such transactions. See “Use of Proceeds.”

No Public Market

Risk Factors

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

Summary Historical and Unaudited Pro Forma Consolidated Financial Data of Energy Future Competitive Holdings Company and its Subsidiaries

The following table sets forth our summary historical consolidated financial data and summary unaudited pro forma consolidated financial data as of and for the periods indicated. The historical financial data as of December 31, 2007 (Successor) and 2006 (Predecessor) and for the period from October 11, 2007 through December 31, 2007 (Successor), the period from January 1, 2007 through October 10, 2007 (Predecessor) and for the years ended December 31, 2006 and 2005 (Predecessor) have been derived from our audited historical consolidated financial statements and related notes included elsewhere in this prospectus. The historical financial data as of December 31, 2005 has been derived from our audited historical consolidated financial statements that are not included herein. The historical financial data as of September 30, 2008 (Successor) and for the nine months ended September 30, 2008 (Successor) and 2007 (Predecessor) have been derived from our unaudited historical interim condensed consolidated financial statements and related notes included elsewhere in this prospectus which have been prepared on a basis consistent with our audited historical consolidated financial statements. In the opinion of our management, such unaudited interim financial data reflects all adjustments, consisting only of normal and recurring adjustments, necessary for the fair presentation of the results for those periods. The results of operations for the interim periods, for seasonal and other factors, are not necessarily indicative of the results to be expected for the full year or any future period.

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

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


	Historical										Pro Forma
	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007							Year Ended December 31, 2007
						Year Ended December 31,
						2006		2005
	(millions of dollars, except ratios and per share amounts)
Statement of Income Data:
Operating revenues(a)	$	1,671		$	6,844	$	9,396	$	10,824		$	8,562
Income (loss) from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles		(1,266	)		1,306		2,501		1,816			(1,427	)
Loss from discontinued operations, net of tax effect		—			—		—		(8	)
Extraordinary loss, net of tax effect		—			—		—		(50	)
Cumulative effect of changes in accounting principles, net of tax effect		—			—		—		(8	)
Preferred stock dividends		—			—		—		3
Net income (loss) available for common stock		(1,266	)		1,306		2,501		1,747
Ratio of earnings to fixed charges(b)		—			5.88		10.84		5.04			—
Ratio of earnings to combined fixed charges and preference dividends(b)		—			5.88		10.84		5.01			—


	Successor		Predecessor
	December 31, 2007		December 31,
	December 31, 2007		2006		2005
	(millions of dollars)
Balance Sheet Data:
Total assets—end of year(c)	$	49,152	$	21,149	$	20,890
Property, plant & equipment—net—end of year		20,545		10,344		9,994
Total goodwill and intangible assets		22,197		526		522
Total debt(d)		31,402		4,084		4,444
Total preferred stock and stock of subsidiaries(e)		—		—		—
Total shareholders’ equity		4,003		7,943		5,640


	Historical
	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31,
							2006			2005
	(millions of dollars, except ratios)
Statement of Cash Flows Data:
Cash flows provided by (used in) operating activities from continuing operations	$	(248	)	$	1,231		$	4,757		$	2,580
Cash flows provided by (used in) financing activities from continuing operations		1,488			895			(1,265	)		(61	)
Cash flows provided by (used in) investing activities from continuing operations		(1,881	)		(1,277	)		(3,497	)		(2,572	)
Other Financial Data:
Capital expenditures, including nuclear fuel	$	519		$	1,585		$	908		$	1,099

(a)

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

(b)

For the period from October 11, 2007 through December 31, 2007, fixed charges and combined fixed charges and preference dividends exceeded earnings by $1.941 billion. For pro forma year ended December 31, 2007, fixed charges and combined fixed charges and preference dividends exceeded earnings by $2.355 billion.

(c)

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

(d)	Includes long-term debt, including amounts due currently, and short-term borrowings and EFH Corp. debt guaranteed by EFC Holdings and pushed down to to EFC Holdings’ financial statements.

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


	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
	(millions of dollars, except ratios and per share amounts)
Statement of Income Data:
Operating revenues(a)	$	7,809		$	6,624
Income (loss) from continuing operations		(943	)		1,232
Income from discontinued operations, net of tax effect		—			—
Net income (loss) available for common stock		(943	)		1,232
Ratio of earnings to fixed charges(b)		—			5.79
Ratio of earnings to combined fixed charges and preference dividends(b)		—			5.79


	Successor
	September 30, 2008
	(millions of dollars)
Balance Sheet Data:
Total assets—end of period	$	52,147
Property, plant & equipment—net—end of period		21,143
Total goodwill and intangible assets		21,384
Total debt(c)		34,337
Total preferred stock and stock of subsidiaries(d)		—
Total shareholders’ equity		3,021


	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
	(millions of dollars)
Statement of Cash Flows Data:
Cash flows provided by operating activities	$	865		$	774
Cash flows provided by financing activities		2,914			954
Cash flows used in investing activities		(2,122	)		(1,107	)

Other Financial Information:
Capital expenditures, including nuclear fuel		1,514			1,584

(a)

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

(b)	Fixed charges and combined fixed charges and preference dividends exceeded earnings by $1.436 billion for the nine months ended September 30, 2008.

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

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

Note: Although EFC Holdings continued as the same legal entity after the Merger, its “Selected Financial Data” for periods preceding the Merger and for the period succeeding the Merger are presented as the consolidated financial statements of the “Predecessor” and the “Successor”, respectively. The consolidated financial statements of the Predecessor have been prepared on the same basis as the audited financial statements included in EFC Holdings’ Annual Report for the year ended December 31, 2006 with the exception of the adoption of FIN 48, a change in presentation related to EFC Holdings’ adoption of FIN 39-1 and a change in classification to report the results of commodity hedging and trading activities on a separate line in the income statement instead of within operating revenues. (See Note 1 to the 2007 year-end Financial Statements and the September 30, 2008 Financial Statements “Basis of Presentation”.) The consolidated financial statements reflect the application of “purchase accounting” (for the Successor periods) and contributions of certain subsidiaries and net assets from EFH Corp. that were accounted for in a manner similar to a pooling of interests.

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 invest in the notes. Any of the following risks could materially and adversely affect our business, financial condition, operating results or cash flow; however, the following risks are not our only risks. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial also may materially and adversely affect our business, financial condition or results of operations. In such a case, the trading price of the notes could decline or we may not be able to make payments of interest and principal on the notes, and you may lose all or part of your original investment.

Risks Related to the Notes

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

We do not intend to apply for a listing of the notes on a securities exchange or any automated dealer quotation system. We cannot assure you as to the liquidity of markets that may develop for the notes, your ability to sell the notes or the price at which you would be able to sell the notes. Certain financial institutions have advised us that they intend to make a market in the notes as permitted by applicable laws and regulations; however, those entities are not obligated to make a market in any of the notes, and they may discontinue their market-making activities at any time without notice. Therefore, an active market for any of the notes, if developed, may not continue. Because Goldman, Sachs & Co. and its respective affiliates may be considered affiliates of ours, they are required to deliver a current “market-maker” prospectus in connection with any secondary market sale of the notes, which may affect their ability to continue market-making activities. 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 notes. The market, if any, for any of the notes may not be free from similar disruptions and any such disruptions may adversely affect the prices at which you may sell your notes. In addition, the notes may trade at a discount from your purchase price, depending upon prevailing interest rates, the market for similar notes, our performance and other factors.

EFH Corp., our parent, is highly leveraged and will rely upon us for a significant amount of its cash flows.

EFH Corp. is a holding company and substantially all of its consolidated assets are held by its subsidiaries. As of September 30, 2008, we held approximately 77% of EFH Corp.’s consolidated assets. For the year ended December 31, 2007 and for the nine-month period ended September 30, 2008, we represented 85% and 87%, respectively, of EFH Corp.’s consolidated revenues. Accordingly, EFH Corp. depends upon us for a significant amount of EFH Corp.’s cash flows and ability to pay its obligations.

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

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

If cash flows and capital resources are insufficient to fund our debt service obligations, we could face substantial liquidity problems and might be forced to reduce or delay investments and capital expenditures, or to dispose of assets or operations, seek additional capital or restructure or refinance indebtedness, including the notes. These alternative measures may not be successful or may not be adequate for us to meet our debt service

obligations then due. Additionally, our debt agreements, including the indenture governing the notes, limit the use of the proceeds from any disposition; as a result, we may not be allowed, under these documents, to use proceeds from such dispositions to satisfy all current debt service obligations.

If we default on obligations to pay indebtedness, we may not be able to make payments on the notes.

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

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

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

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

We have the option to pay interest on the toggle notes in cash or PIK interest for any interest payment period prior to November 1, 2012. For U.S. federal income tax purposes, the existence of this option means that none of the interest payments on the toggle notes are qualified stated interest for U.S. federal income tax purposes (as defined under “Certain U.S. Federal Income Tax Consequences—Certain Tax Consequences to U.S. Holders—Toggle Notes”). Consequently, the toggle notes are treated as having been issued with original issue discount for U.S. federal income tax purposes, and U.S. holders (as defined under “Certain U.S. Federal Income Tax Consequences”) will be required to include the original issue discount in gross income on a constant yield to maturity basis, regardless of whether interest is paid currently in cash. See “Certain U.S. Federal Income Tax Consequences—Certain Tax Consequences to U.S. Holders—Toggle Notes.”

U.S. holders will be required to pay U.S. federal income tax on accrual of original issue discount on the Series B cash-pay notes.

Because the “stated redemption price at maturity” of the Series B cash-pay notes exceeds their “issue price” by more than the statutory de minimis threshold, the Series B cash-pay notes are treated as having been being issued with original issue discount for U.S. federal income tax purposes. A U.S. holder (as defined under “Certain U.S. Federal Income Tax Consequences”) of a Series B cash-pay note will be required to include such original issue discount in gross income as it accrues, in advance of the receipt of cash attributable to that income and regardless of the U.S. holder’s regular method of accounting for U.S. federal income tax purposes. See “Certain U.S. Federal Income Tax Consequences—Certain Tax Consequences to U.S. Holders—Series B Cash-Pay Notes” for more detail.

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

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

Your right to receive payments on the notes and the guarantees is effectively subordinated to those lenders who have a security interest in our assets.

The Issuer’s obligations under the notes and the Guarantors’ obligations under their guarantees of the notes are unsecured, but TCEH’s obligations under the TCEH Senior Secured Facilities and the Guarantors’ obligations under their guarantee of the TCEH Senior Secured Facilities are secured by a security interest in substantially all of our tangible and intangible assets and all of our capital stock and promissory notes and the capital stock of each of our existing and future domestic subsidiaries and 65% of the capital stock of the foreign subsidiaries of the Guarantors. If TCEH is declared bankrupt or insolvent, or if TCEH defaults under the TCEH Senior Secured Facilities, the lenders could declare all of the funds borrowed thereunder, together with accrued interest, immediately due and payable. If TCEH were unable to repay such indebtedness, 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. Furthermore, if the lenders foreclose on the pledged assets and sell the pledged equity interests of a Guarantor under the notes, then a Guarantor will be released from its guarantee of the notes automatically and immediately upon such sale. In any such event, because the notes will not be secured by any of our assets or the equity interests in a guarantor, it is possible that there would be no assets remaining from which your claims could be satisfied or, if any assets remained, they might be insufficient to satisfy your claims fully.

As of September 30, 2008, we had $24.0 billion principal amount of secured indebtedness, $23.6 billion of which was indebtedness under the TCEH Senior Secured Facilities, and TCEH had approximately $1.6 billion of available borrowing capacity under the TCEH Senior Secured Facilities (excluding amounts available under the TCEH Commodity Collateral Posting Facility).

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

The notes are guaranteed by EFC Holdings and primarily all of TCEH’s subsidiaries. The issuance of the guarantees by the guarantors may be subject to review under state and federal laws if a bankruptcy, liquidation or reorganization case or a lawsuit, including in circumstances in which bankruptcy is not involved, were commenced at some future date by, or on behalf of, our unpaid creditors or the unpaid creditors of a guarantor.

Under the federal bankruptcy laws and comparable provisions of state fraudulent transfer laws, a court may void or otherwise decline to enforce a guarantor’s guarantee, or subordinate such guarantee to such guarantor’s existing and future indebtedness. While the relevant laws may vary from state to state, a court might do so if it found that when a guarantor entered into its guarantee or, in some states, when payments became due under such guarantee, such guarantor received less than reasonably equivalent value or fair consideration and either:

•

was insolvent or rendered insolvent by reason of such incurrence;

•

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

•

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

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

•

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

•

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

•

it could not pay its debts as they become due.

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

The interests of our controlling stockholders 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 the stockholders of EFH Corp.

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 of EFH Corp., might conflict with your interests as a note holder. The Sponsor Group may also

have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in their judgment, could enhance their equity investments, even though such transactions might involve risks to you as a note holder.

Risks Related to Our Indebtedness and Our Debt Agreements

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

We are highly leveraged. As of September 30, 2008, our consolidated principal amount of total debt (short term borrowings and long-term debt, including amounts due currently) totaled $34.5 billion, excluding $186 million of unamortized discounts and including $2.250 billion of EFH Corp. Notes (see Note 7 to the September 30, 2008 Financial Statements). Our substantial leverage could have important consequences, including:

•

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

•

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

•

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

•

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

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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, and

•

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

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

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

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

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

At September 30, 2008, we had $3.6 billion aggregate principal amount of variable rate long-term indebtedness (excluding $1.25 billion of long-term indebtedness associated with the TCEH Letter of Credit Facility that is invested at a variable rate), taking into account interest rate swaps that fix the interest rate on $16.55 billion in notional amount of variable rate indebtedness. As a result, as of September 30, 2008, the impact of a 100 basis point increase in interest rates would increase our annual interest expense by approximately

$36 million. See discussion of interest rate swap transactions in “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Significant Developments-Interest Rate Swap Transactions”.

Our pro forma interest expense, net for the year ended December 31, 2007 was $2.8 billion.

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

Our debt agreements, including the Indenture and the TCEH Senior Secured Facilities, contain various covenants and other restrictions that limit our ability to engage in specified types of transactions, and which may adversely affect our ability to operate our businesses. These covenants and other restrictions limit our and our restricted subsidiaries’ ability to, among other things:

•

incur additional indebtedness or issue preferred shares;

•

pay dividends on, repurchase or make distributions in respect of capital stock or make other restricted payments;

•

make investments;

•

sell or transfer assets;

•

create liens;

•

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

•

enter into transactions with our affiliates.

There are a number of important limitations and exceptions to these covenants and other restrictions. You should read “Description of the Notes” and Note 16 to the 2007 year-end Financial Statements and Note 7 to the September 30, 2008 Financial Statements for a description of these covenants and other restrictions.

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

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

In addition, as described in “The Transactions—Ring-Fencing,” EFH Corp. and Oncor have implemented a number of ring-fencing measures to further separate Oncor, its immediate parent, Oncor Holdings, and Oncor Holdings’ other subsidiaries, from Texas Holdings and its other subsidiaries. Those measures include Oncor not guaranteeing or pledging any of its assets to secure the indebtedness of Texas Holdings and its other subsidiaries. Accordingly, Oncor’s assets will not be available to repay any of the notes or the TCEH Senior Secured Facilities.

Risks Related to Our Structure

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

Our cash flows and ability to meet our obligations are largely dependent upon the earnings of our subsidiaries and the payment of such earnings to us in the form of dividends, distributions, loans or otherwise, and repayment of loans or advances from us. These subsidiaries are separate and distinct legal entities and have

no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. Any decision by a subsidiary to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise, will depend on, among other things, the subsidiary’s results of operations, financial condition, cash requirements, contractual restrictions and other factors. In addition, a subsidiary’s ability to pay dividends may be limited by existing or future debt agreements or applicable law.

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

Oncor may not make any distributions to EFH Corp., which may result in EFH Corp. depending solely on distributions from us.

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

Neither holders of the notes nor holders of the EFH Corp. Notes will be entitled to look to the assets, financial condition or results of operations of Oncor for payments of interest or principal on the notes or the EFH Corp. Notes, respectively.

As part of the ring-fencing measures implemented by EFH Corp. and Oncor, a majority of the members of the board of directors of Oncor are required to be independent from EFH Corp. Other than the initial independent directors that were appointed within 30 days of the consummation of the Merger, the independent directors are required to be appointed by the nominating committee of Oncor Holdings, a majority of whose members are required to be independent from EFH Corp. The organizational documents of Oncor give these independent directors acting by majority vote and, during certain periods, any director designated by Texas Transmission Investment LLC the express right to prevent distributions from Oncor if they determine that it is in the best interests of Oncor to retain such amounts to meet expected future requirements. Accordingly, there can be no assurance that Oncor will make any distributions to EFH Corp. which might in turn be contributed to us.

Risks Related to Our Businesses

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

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

Our businesses are subject to changes in state and federal laws (including PURA, the Federal Power Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act and the Energy Policy Act of 2005) and changing governmental policy and regulatory actions (including those of the PUCT, the Electric

Reliability Organization, the Texas Regional Entity, the RRC, the TCEQ, the FERC, the EPA and the NRC) and also the rules, guidelines and protocols of ERCOT with respect to matters including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, recovery of costs and investments, decommissioning costs, market behavior rules, present or prospective wholesale and retail competition and environmental matters. TCEH, along with other market participants, is subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA that are administered by the PUCT and ERCOT, and, with respect to its wholesale power sales outside the ERCOT market, is subject to market behavior and other competition-related rules and regulations under the Federal Power Act that are administered by the FERC. Changes in, revisions to, or reinterpretations of existing laws and regulations (for example, with respect to prices at which TCEH may sell electricity or with respect to the required permits for the three lignite-fueled generation units currently under construction) may have an adverse effect on our businesses.

Several pieces of legislation were introduced in the Texas legislature during 2007 that, if passed, may have had a material impact on us and our financial prospects, including, for example, legislation that would have:

•

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

•

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

•

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

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

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

We are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, environmental and injuries and damages issues, among other matters, such as challenges (to which we may or may not be a direct party) to the permits that have been issued or may be issued for the new lignite-fueled generation units currently under construction. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these assessments and estimates, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These assessments and estimates are based on the information available to management at the time and involve a significant amount of management judgment. Actual outcomes or losses may differ materially from current assessments and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on our results of operations.

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

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

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

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

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

In addition to competition from the incumbent retail electric provider, TXU Energy may face competition from a number of other energy service providers, or other energy industry participants, who may develop businesses that will compete with TXU Energy and nationally branded providers of consumer products and services. Some of these competitors or potential competitors may be larger or better capitalized than TXU Energy. If there is inadequate potential margin in these retail electric markets, it may not be profitable for TXU Energy to compete in these markets.

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

We are not guaranteed any rate of return on capital investments in our competitive businesses. We market and trade electricity and natural gas, including electricity from our own generation facilities and generation contracted from third parties, as part of our wholesale markets operation. Our results of operations depend in large part upon market prices for electricity, natural gas, uranium and coal in our regional market and other competitive markets and upon prevailing retail electricity rates, which may be impacted by actions of regulatory authorities. Market prices may fluctuate substantially over relatively short periods of time. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, at times there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets. Further, TXU Energy granted price discounts to certain of its customers in connection with the Merger, and is providing price protection to these customers through December 2008. In addition, TXU Energy committed in 2006 to not increase prices above then current levels through 2009 for qualifying residential customers who remain on certain plans with rates that were then equal to the price-to-beat rate.

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

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

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severe or unexpected weather conditions;

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seasonality;

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changes in electricity and fuel usage;

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illiquidity in the wholesale power or other markets;

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transmission or transportation constraints, inoperability or inefficiencies;

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availability of competitively-priced alternative energy sources;

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

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changes in generation efficiency and market heat rates;

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outages at our generation facilities or those of competitors;

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

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

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

All of Luminant Power’s generation facilities are located in the ERCOT market, a market with limited interconnections to other markets. Wholesale electricity prices in the ERCOT market generally correlate with the price of natural gas because marginal demand is generally supplied by natural gas-fueled generation plants. Wholesale electricity prices also correlate with market heat rates (a measure of efficiency of the marginal price-setting generator of electricity), which could fall if demand for electricity were to decrease or if additional generation facilities are built in ERCOT. Accordingly, the contribution to earnings and the value of Luminant Power’s baseload (lignite/coal-fueled and nuclear) generation assets, which provided a substantial portion of our supply volumes in 2007 and the first nine months of 2008, are dependent in significant part upon the price of natural gas and market heat rates. As a result, Luminant Power’s baseload generation assets could significantly decrease in profitability and value if natural gas prices or market heat rates fall.

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

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

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

To the extent we engage in hedging and risk management activities, we are exposed to the risk that counterparties that owe us money, energy or other commodities as a result of market transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, we might be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. In such event, we might incur losses in addition to amounts, if any, already paid to the counterparties. ERCOT market participants are also exposed to risks that another ERCOT market participant may default in its obligations to pay ERCOT for power taken, in which case such costs, to the extent not offset by posted security and other protections available to ERCOT, may be allocated to various non-defaulting ERCOT market participants, including us.

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

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

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

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inadequacy or lapses in maintenance protocols;

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

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the costs of storage, handling and disposal of nuclear materials;

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the costs of procuring nuclear fuel;

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the costs of securing the plant against possible terrorist attacks;

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

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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:

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

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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 plants generally has been very good, accidents and other unforeseen problems have occurred both in the U.S. and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impact, and property damage. Any accident, or perceived accident, could result in significant liabilities and damage our reputation. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage.

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

The operation and maintenance of electricity generation facilities involves many risks, including, as applicable, start-up risks, breakdown or failure of facilities, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source or the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output, efficiency or dependability, the occurrence of any of which could result in lost revenues and/or increased expenses. A significant number of Luminant’s facilities were constructed many years ago. In particular, older generating equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep operating at peak efficiency. 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 results of operations and financial condition.

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

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

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

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

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

Increasing attention to potential environmental effects of “greenhouse” gas emissions may result in new regulation and restrictions on emissions of certain gases that may be contributing to warming the earth’s atmosphere. Several bills addressing climate change have been introduced in the U.S. Congress and, in April 2007, the U.S. Supreme Court issued a decision ruling the EPA improperly declined to address carbon dioxide impacts in a rulemaking related to new motor vehicle emissions. While this decision is not directly applicable to power plant emissions, the reasoning of the decision could affect other regulatory programs. The impact of any

future greenhouse gas legislation or other regulation will depend in large part on the details of the requirements and the timetable for mandatory compliance. Although we continue to assess the financial and operational risks posed by possible future legislative changes pertaining to greenhouse gas emissions, we are currently unable to predict any future impact from these changes on our financial condition and operations.

Our growth strategy, including investment in three new lignite-fueled generation units, may not be executed as planned which could adversely impact our financial condition and results of operations.

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

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

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

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

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

Ongoing performance improvement initiatives may not achieve desired cost reductions and may instead result in significant additional costs if unsuccessful.

The implementation of performance improvement initiatives identified by management may not produce the desired reduction in costs and may result in disruptions arising from employee displacements and the rapid pace of changes to organizational structure and operating practices and processes. Specifically, we are subject to the risk that our outsourcing arrangements for business support services may not produce the desired cost savings. In cases where any such outsourcing arrangement is terminated, such as our joint venture outsourcing arrangement with Capgemini, or if any party performing such business support services becomes financially unable to perform its obligations, we would incur transition costs, which would likely be significant, and would be subject to operational difficulties. Such additional costs or operational difficulties could have an adverse effect on our business and financial prospects.

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

TXU Energy’s retail business requires access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, drivers license numbers, social security numbers and bank account information. TXU Energy’s retail business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the retail business. If a significant breach occurred, the reputation of TXU Energy’s retail business may be adversely affected, customer confidence may be diminished, or TXU Energy’s retail business may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the business and/or results of operations.

TXU Energy relies on the infrastructure of local utilities or independent transmission system operators to provide electricity to, and to obtain information about, its customers. Any infrastructure failure could negatively impact customer satisfaction and could have a material negative impact on its business and results of operations.

TXU Energy depends on transmission and distribution facilities owned and operated by unaffiliated utilities, as well as Oncor’s facilities, to deliver the electricity it sells to its customers. If transmission capacity is inadequate, TXU Energy’s ability to sell and deliver electricity may be hindered, it may have to forgo sales or it may have to buy more expensive wholesale electricity than is available in the capacity-constrained area. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where TXU Energy has a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower profits. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to TXU Energy’s customers could negatively impact the satisfaction of its customers with its service.

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

TXU Energy offers its customers a bundle of services that include, at a minimum, electricity plus transmission, distribution and related services. The prices TXU Energy charges for its bundle of services or for the various components of the bundle, any of which may be fixed by contract with the customer for a period of time, could fall below TXU Energy’s underlying cost to provide the components of such services.

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

In connection with the Merger, TXU Energy implemented a 15% price reduction through December 31, 2008 for residential customers in our historical service territory who have not already switched to one of the pricing plans other than the basic month-to-month plan. In addition, TXU Energy committed in 2006 to not increase prices above then current levels through 2009 for qualifying residential customers who remain on certain plans with rates that were then equal to the price-to-beat rate. The prices TXU Energy charges during this period could fall below TXU Energy’s underlying cost to provide electricity.

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

The PUCT may at any time initiate an investigation into whether TXU Energy is compliant with PUCT Substantive Rules and whether it has met all of the requirements for REP certification, including financial requirements, so that it can maintain its REP certification. Any removal or revocation of a REP certification would mean that TCEH or TXU Energy, as applicable, would no longer be allowed to provide electric service to retail customers. Such decertification would have an adverse effect on TXU Energy and its financial prospects.

Changes in technology may reduce the value of our generation plants and may significantly impact our businesses in other ways as well.

Research and development activities are ongoing to improve existing and alternative technologies to produce electricity, including gas turbines, fuel cells, microturbines and photovoltaic (solar) cells. It is possible that advances in these or other technologies will reduce the costs of electricity production from these technologies to a level that will enable these technologies to compete effectively with the traditional generation plants owned by Luminant. While demand for electric energy services is generally increasing throughout the U.S., the rate of construction and development of new, more efficient generation facilities may exceed increases in demand in some regional electric markets. Consequently, where we have facilities, the profitability and market value of our generation assets could be significantly reduced. Also, electricity demand could be reduced by increased conservation efforts and advances in technology, which could likewise significantly reduce the value of our generation assets. Changes in technology could also alter the channels through which retail electric customers buy electricity. To the extent self-generation facilities become a more cost-effective option for certain customers, our revenues could be reduced.

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

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

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

Substantially all of our competitive businesses are located in the ERCOT market, which is currently in the process of contemplating a transition from a zonal market structure with four Congestion Management Zones to a

nodal market structure that would directly manage congestion on a localized basis. In a nodal market, the prices received and paid for power would be based on pricing determined at specific interconnection points on the transmission grid (i.e., Locational Marginal Pricing), which could result in lower revenues or higher costs for our competitive businesses. This market structure change could have a significant impact on the profitability and value of our competitive businesses depending on how the Locational Marginal Pricing develops.

Our future results of operations may be negatively impacted by settlement adjustments determined by ERCOT related to prior periods.

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

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

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

TCEH’s credit ratings could negatively affect our ability to access capital and could require us or our subsidiaries to post collateral or repay certain indebtedness.

Downgrades in TCEH’s long-term debt ratings generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease and might trigger liquidity demands pursuant to the terms of commodity contracts, leases or other agreements. In connection with the Merger, Fitch, Moody’s and S&P downgraded TCEH’s long term debt ratings. On November 3, 2008, Moody’s announced that it changed the rating outlook for TCEH to negative from stable, stating that the change was primarily related to the decision to elect the PIK interest option on the toggle notes for the interest due on May 1, 2009.

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

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

Our businesses are capital intensive. We rely on access to financial markets as a significant source of liquidity for capital requirements not satisfied by cash-on-hand or operating cash flows. The inability to raise capital on favorable terms, particularly during times of uncertainty similar to that which is currently being experienced in the financial markets, could impact our ability to meet our shortened liquidity requirements and to

sustain and grow our businesses and would likely increase capital costs. Our access to the financial markets could be adversely impacted by various factors, such as:

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

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economic weakness in the ERCOT or general U.S. markets;

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changes in interest rates;

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a deterioration of our credit or the credit of our subsidiaries or a reduction in TCEH’s credit ratings;

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a deterioration of the credit or bankruptcy of one or more of TCEH’s lenders under its liquidity facilities that affects any such lender’s ability to make loans to TCEH;

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volatility in commodity prices that increases margin or credit requirements;

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a material breakdown in our risk management procedures; and

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

Although we expect to actively manage the liquidity exposure of existing and future hedging arrangements, given the size of the long-term hedging program, any significant increase in the price of natural gas could result in our being required to provide cash or letter of credit collateral in substantial amounts. Any perceived reduction in our credit quality could result in clearing agents or other counterparties requesting additional collateral. We have potential credit concentration risk related to the limited number of lenders that provide us liquidity to support our hedging program. A deterioration of the credit quality of such lenders could materially affect our ability to continue such program on acceptable terms.

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

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

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

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

In accordance with SFAS 142, goodwill and certain other intangible assets recorded in connection with the Merger are not amortized but are reviewed annually or more frequently for impairment, if certain conditions exist, and may be impaired. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings which could reflect material adverse impacts on our reported results of operations and financial position in future periods.

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

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

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

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

FORWARD-LOOKING STATEMENTS

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

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

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allowed prices;

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industry, market and rate structure;

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purchased power and recovery of investments;

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operations of nuclear generating facilities;

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operations of mines;

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acquisitions and disposal of assets and facilities;

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development, construction and operation of facilities;

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decommissioning costs;

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present or prospective wholesale and retail competition;

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changes in tax laws and policies; and

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

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legal and administrative proceedings and settlements;

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general industry trends;

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our ability to attract and retain profitable customers;

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our ability to profitably serve our customers;

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restrictions on competitive retail pricing;

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changes in wholesale electricity prices or energy commodity prices;

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

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

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

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

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

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changes in business strategy, development plans or vendor relationships;

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access to adequate transmission facilities to meet changing demands;

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

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

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commercial bank market and capital market conditions;

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competition for new energy development and other business opportunities;

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the impact of recent economic conditions on our customers;

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

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changes in technology used by and services offered by us;

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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;

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

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significant changes in critical accounting policies;

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actions by credit rating agencies;

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our ability to implement cost reduction initiatives; and

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with respect to our lignite coal-fueled generation construction and development program, more specifically, our ability to fund such investments, changes in competitive market rules, unexpected judicial rulings, changes in environmental laws or regulations, changes in electric generation and emissions control technologies, changes in projected demand for electricity, our ability and the ability of our contractors to attract and retain, at projected rates, skilled labor for constructing the new generating units, changes in wholesale electricity prices or energy commodity prices, transmission capacity and constraints, supplier performance risk, changes in the cost and availability of materials necessary for the construction program and our ability to manage the significant construction, commissioning and start-up program to a timely conclusion with limited cost overruns.

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

INDUSTRY AND MARKET INFORMATION

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

THE TRANSACTIONS

The Merger

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

Equity Contributions

Debt Financing

In connection with the Merger, in addition to the Equity Contributions described above, EFH Corp. entered into the EFH Senior Interim Facility and TCEH entered into the TCEH Senior Secured Facilities and the TCEH Senior Interim Facility, in each case, arranged by a consortium of arrangers and bookrunners (the “Arranger Group”). For a description of the material terms of each component of the Debt Financing, see Note 16 to the 2007 year-end Financial Statements and Note 7 to the September 30, 2008 Financial Statements.

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

EFH Senior Interim Facility

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

TCEH Senior Secured Facilities

The TCEH Senior Secured Facilities are comprised of:

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

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

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

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

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

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

TCEH Senior Interim Facility

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

Receivables Program

The Receivables Program, a commercial paper-backed accounts receivables securitization program, was amended in connection with the Merger. Certain financial tests relating to TCEH and the originators that could have affected the amount of available funding under the program or caused a termination event or a default, including TCEH’s debt to capital (leverage) and fixed charge coverage ratios, were deleted and replaced with other tests. As amended, among other things, the amount of customer deposits held by the originators can reduce funding available under the program so long as TCEH’s long-term senior unsecured debt rating is lower than investment grade. Also, the originators will continue to be eligible to participate in the program so long as TCEH provides the required form of parent guaranty. Concurrently with the amendment, the financial institutions required that Oncor repurchase all of the receivables it had previously sold to TXU Receivables Company. Subsequent to the Merger, only subsidiaries of TCEH have participated in the accounts receivables securitization program.

Oncor Revolving Credit Facility

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

Ring-Fencing

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

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

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

Debt Repayment

Pursuant to the terms of the Merger Agreement, EFH Corp. commenced offers to purchase and consent solicitations with respect to the Specified Notes. In connection with the Merger, EFH Corp. and we redeemed and repaid an aggregate of approximately $5.5 billion of existing indebtedness of EFH Corp. and its subsidiaries (including the Specified Notes, but excluding indebtedness of Oncor), including debt that became payable upon the consummation of the Merger. See Note 16 to the 2007 year-end Financial Statements.

USE OF PROCEEDS

This prospectus may be delivered in connection with the resale of notes by the Market Maker and its affiliates in market-making transactions in the notes in the secondary market. We will not receive any of the proceeds from such transactions.

CAPITALIZATION

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


Debt:
EFC Holdings:
Secured debt(a)	$	99
Unsecured debt(b)		2,259

Total EFC Holdings debt		2,358

TCEH:
TCEH Senior Secured Facilities		23,569
Notes		6,750
Other secured debt		285
Other unsecured debt		1,375

Total TCEH debt		31,979

Total consolidated debt		34,337
Total shareholders’ equity		3,021

Total capitalization	$	37,358

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

(b)	Includes $2.250 billion of EFH Corp. Notes. See Note 7 to the September 30, 2008 Financial Statements under “EFH Corp. Notes Issued Subsequent to the Merger” for discussion of this debt push down and EFC Holdings’ guarantee of the EFH Corp. Notes.

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED INCOME (LOSS)

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

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

•

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

•

audited consolidated financial statements and accompanying notes of EFC Holdings as of December 31, 2007 and for each of the three years in the period ended December 31, 2007 included elsewhere in this prospectus, and

•

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

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

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

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

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED INCOME (LOSS)

(millions of dollars)


	Historical(a)						Pro Forma Adjustments			Pro Forma
	Predecessor			Successor						Pro Forma
	January 1, 2007 through October 10, 2007			October 11, 2007 through December 31, 2007						Year Ended December 31, 2007
Operating revenues	$	6,884		$	1,671		$	7	(b)	$	8,562
Fuel, purchased power costs and delivery fees		(3,209	)		(852	)		(205	)(c)		(4,266	)
Net gain (loss) from commodity hedging and trading activities		(554	)		(1,492	)		—			(2,046	)
Operating costs		(471	)		(124	)		1			(594	)
Depreciation and amortization		(253	)		(315	)		(276	)(d)		(844	)
Selling, general and administrative expenses		(452	)		(153	)		—			(605	)
Franchise and revenue-based taxes		(83	)		(30	)		—			(113	)
Other income		59			2			—			61
Other deductions		20			(5	)		—			15
Interest income		312			9			—			321
Interest expense and related charges		(329	)		(652	)		(1,784	)(e)		(2,765	)

Income (loss) before income taxes		1,924			(1,941	)		(2,257	)		(2,274	)
Income tax (expense) benefit		(618	)		675			790	(f)		847

Income (loss) from continuing operations	$	1,306		$	(1,266	)	$	(1,467	)	$	(1,427	)

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

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED INCOME (LOSS)

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

(b)

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

(c)

Fuel, purchased power costs and delivery fees — Represents pro forma adjustments required to record the amortization related to the fair value of intangible assets related to contracts and other legal or economic rights. For purposes of this adjustment, amortization was determined for different categories of intangible assets based on a straight-line method over useful lives ranging from 2 to 30 years. These adjustments increased costs and expenses by approximately $205 million for the year ended December 31, 2007. Of the $205 million, $158 million relates to intangible asset and liability amortization. The amortization consists of $79 million for favorable purchase and sales contracts with a weighted average life of 11 years, and $80 million for emission and renewable energy credits with a weighted average life of 23 years, slightly offset by $1 million for unfavorable purchase and sales contracts with a weighted average life of 11 years. See Note 3 and Note 27 (under Other Noncurrent Liabilities and Deferred Credits) to the 2007 year-end Financial Statements for additional details of these intangible assets and liabilities. These adjustments are required to be made to the fuel, purchased power costs and delivery fees line item in the income statement since the activity associated with the underlying contracts or other legal or economic rights is reported as a component of such costs. Adjustments also include $47 million in additional amortization expense related to nuclear fuel balances included in property, plant and equipment, reflecting a $299 million increase in the valuation of the nuclear fuel amortized over a five-year life based on a straight-line amortization method.

(d)

Depreciation and amortization expense — Represents the pro forma adjustment required to adjust property, plant and equipment to record power generation assets and other tangible property at their estimated fair values, as well as to record amortization of the fair value of customer relationship-based intangible assets. For purposes of this adjustment, depreciation and amortization was determined for different categories of property and intangible assets based on a straight-line method over estimated useful lives ranging from 4 to 45 years. These adjustments increased depreciation and amortization expense approximately $276 million for the year ended December 31, 2007, which consists of a $201 million increase in depreciation of property plant and equipment and a $75 million increase in amortization expense. The increase in depreciation expense primarily reflects depreciation on a straight-line basis of an increase of approximately $8 billion in the value of power generation assets with a weighted average useful life of 26 years. Depreciation expense is based on composite depreciation rates that reflect blended estimates of the lives of major asset components as compared to depreciation expense calculated on an asset-by-asset basis (see Note 1 to the 2007 year-end Financial Statements). The increase in amortization expense reflects amortization on a straight-line basis of the retail customer relationship intangible asset described in Note 3 to the 2007 year-end Financial Statements over the 4 year weighted average life of the asset.

(e)

Interest expense — Represents pro forma adjustments related to the increase in interest expense as a result of the borrowings made to finance the Merger, less certain interest expense associated with the debt that was repaid as part of the Merger. In connection with the Merger, approximately $29,232 million of new debt was incurred by EFC Holdings and its subsidiaries, with approximately $4,315 million of existing debt repaid,

resulting in a net increase in debt of approximately $24,917 million. The new debt includes $2,250 million principal amount of EFH Corp. Notes guaranteed by EFC Holdings and reflected on EFC Holdings balance sheet in accordance with SEC Staff Accounting Bulletin Topic 5-J, as it relates to guaranteed debt (see Note 16 to the 2007 year-end Financial Statements under EFH Corp. Notes Issued Subsequent to the Merger for additional discussion). The increase in debt significantly increased the overall interest expense for EFC Holdings. The estimated increase in interest expense was calculated based on an aggregate assumed weighted-average interest rate of approximately 8.59% for the new debt issued in connection with the Merger, adjusted for the repayment of existing debt. The pro forma interest expense adjustment reflects the effect of interest rate swaps with a notional amount of $15.050 billion related to the senior secured term loans of TCEH as if these swaps were effective January 1, 2007. See the table below for summary of the calculation of the annualized increase in interest expense, which was then prorated to the Predecessor 2007 period to calculate the adjustment. Due to the remaining unhedged variable rate long-term debt, as of September 30, 2008, a 1/8 percent change in interest rates would result in an approximate $5 million change in pretax annual interest expense.

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

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


Merger-related long-term debt issuances:	Principal			Interest Rate(a)	Swap Interest Rate(b)	Annualized Interest
TCEH Initial Term Loan Facility maturing October 10, 2014	$	16,450		8.3960	8.0055	$	1,322
TCEH Delayed Draw Term Loan Facility maturing October 10, 2014		2,150		8.3780			180
TCEH Letter of Credit Facility maturing October 10, 2014		1,250		3.6200			45
TCEH Commodity Collateral Posting Facility maturing October 10, 2012		382		4.4730			17
TCEH Fixed Senior Notes due November 1, 2015		3,000		10.2500			308
TCEH Fixed Senior Notes Series B due November 1, 2015		2,000		10.2500			205
TCEH Senior Toggle Notes due November 1, 2016		1,750		10.5000			184
EFH Corp. Fixed Senior Notes maturing October 10, 2014		1,000		10.8750			109
EFH Corp. Fixed Senior Toggle Notes maturing October 10, 2014		1,250		11.2500			141

Total merger-related issuances		29,232		8.5899			2,511

Merger-related retirements:
TCEH credit facilities(c)		(2,055	)	N/A			(117	)
TCEH Floating Senior Notes due September 16, 2008		(1,000	)	6.1940			(62	)
TCEH Fixed Senior Notes due March 15, 2008		(247	)	6.1250			(15	)
TCEH Fixed Senior Notes due March 15, 2013		(995	)	7.0000			(70	)
TCEH fair value swaps(d)		(14	)	N/A			(2	)
EFC Holdings. unamortized discount(d)		(4	)	N/A			(1	)
Consolidated deferred financing costs(d)		—		N/A			(6	)

Total merger-related retirements		(4,315	)				(273	)
Consolidated unamortized fair value discount(d)		(198	)	N/A			28
Consolidated deferred financing costs(d)				N/A			19

Annual increase in interest expense						$	2,285

Pro forma increase in interest expense(e)						$	1,784

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

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

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

(d)	Amortization period assumed to be 7 years.

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

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

ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY AND

SUBSIDIARIES SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

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

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

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


	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007		Year Ended December 31,
	Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007		2006		2005			2004			2003
	(millions of dollars, except ratios and per share amounts)
Statement of Income Data:
Operating revenues(a)	$	1,671		$	6,884	$	9,396	$	10,824		$	9,304		$	8,543
Income (loss) from continuing operations before extraordinary gain (loss) and cumulative effect of changes in accounting principles		(1,266	)		1,306		2,501		1,816			672			736
Loss from discontinued operations, net of tax effect		—			—		—		(8	)		(34	)		(18	)
Extraordinary gain (loss), net of tax effect		—			—		—		(50	)		16			—
Cumulative effect of changes in accounting principles, net of tax effect		—			—		—		(8	)		6			(58	)
Preferred stock dividends		—			—		—		3			2			5
Net income (loss) available for common stock		(1,266	)		1,306		2,501		1,747			658			655

Ratio of earnings to fixed charges(b)		—			5.88		10.84		5.04			2.47			2.63
Ratio of earnings to combined fixed charges and preference dividends(b)		—			5.88		10.84		5.01			2.45			2.60


	Successor			Predecessor
	December 31, 2007			December 31,
	December 31, 2007			2006			2005			2004			2003
	(millions of dollars, except ratios)
Balance Sheet Data:
Total assets—end of year(c)	$	49,152		$	21,149		$	20,890		$	24,833		$	23,989
Property, plant & equipment—net—end of year		20,545			10,344			9,994			16,529			16,677
Goodwill and intangible assets—end of year		22,197			526			522			687			884

Capitalization—end of year
Long-term debt, less amounts due currently		30,762			3,088			3,284			7,571			7,217
Exchangeable preferred membership interests of TCEH(d)		—			—			—			511			497
Preferred stock of subsidiaries (not subject to mandatory redemption)(e)		—			—			—			38			38
Shareholders’ equity		4,003			7,943			5,640			6,373			6,282

Total	$	34,765		$	11,031		$	8,924		$	14,493		$	14,034

Capitalization ratios—end of year
Long-term debt, less amounts due currently		88.5			28.0			36.8			52.2			51.4
Exchangeable preferred membership interests of TCEH(d)		—			—			—			3.5			3.5
Preferred stock of subsidiaries not subject to mandatory redemption(e)		—			—			—			0.3			0.3
Shareholders’ equity		11.5			72.0			63.2			44.0			44.8

Total		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%

Short-term borrowings	$	438		$	818		$	746		$	210		$	—
Long-term debt due currently		202			178			414			218			249

Embedded interest cost on long-term debt—end of period(f)		9.6	%		7.2	%		7.0	%		6.1	%		6.6	%
Embedded dividend cost on preferred stock of subsidiaries—end of period(g)		—	%		—	%		—	%		14.0	%		14.7	%


	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31,
							2006			2005			2004			2003
	(millions of dollars)
Statement of Cash Flows Data:
Cash flows provided by (used in) operating activities from continuing operations	$	(248	)	$	1,231		$	4,757		$	2,580		$	1,838		$	1,959
Cash flows provided by (used in) financing activities from continuing operations		1,488			895			(1,265	)		(61	)		(772	)		(1,944	)
Cash flows (used in) investing activities from continuing operations		(1,881	)		(1,277	)		(3,497	)		(2,572	)		(1,776	)		(712	)

Other Financial Information:
Capital expenditures, including nuclear fuel	$	519		$	1,585		$	908		$	1,099		$	968		$	750

(a)

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

(b)	For the period from October 11, 2007 through December 31, 2007, fixed charges and combined fixed charges and preference dividends exceeded earnings by $1.941 billion.

(c)

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

(d)	Amount is net of discount. In April 2004, EFH Corp. repurchased TCEH’s exchangeable preferred membership interests. Such membership interests were contributed to EFC Holdings in 2005.

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

(f)

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

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

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


	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
	(millions of dollars, except ratios and per share amounts)
Statement of Income Data:
Operating revenues(a)	$	7,809		$	6,624
Net income (loss)		(943	)		1,232
Ratio of earnings to fixed charges(b)		—			5.79
Ratio of earnings to combined fixed charges and preference dividends(b)		—			5.79


	Successor
	September 30, 2008
	(millions of dollars, except ratios)
Balance Sheet Data:
Total assets—end of period	$	52,147
Property, plant & equipment—net—end of period		21,143
Goodwill and intangible assets		21,384

Capitalization—end of period
Long-term debt, less amounts due currently	$	31,562
Preferred stock of subsidiaries (not subject to mandatory redemption)(c)		—
Shareholders’ equity		3,021

Total	$	34,583

Capitalization ratios—end of period
Long-term debt, less amounts due currently		91.3	%
Preferred stock of subsidiaries(c)		—
Shareholders’ equity		8.7

Total		100.0	%

Short-term borrowings	$	2,470
Long-term debt due currently		305
Embedded interest cost on long-term debt—end of period(d)		9.7	%


	Successor			Predecessor
	Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
	(millions of dollars)
Statement of Cash Flows Data:
Cash flows provided by operating activities	$	865		$	774
Cash flows provided by financing activities		2,914			954
Cash flows used in investing activities		(2,122	)		(1,107	)

Other Financial Information:
Capital expenditures, including nuclear fuel		1,514			1,584

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

(b)	Fixed charges and combined fixed charges and preference dividends exceeded earnings by $1.436 billion for the nine months ended September 30, 2008.

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

(d)

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

Note: Although EFC Holdings continued as the same legal entity after the Merger, its “Selected Financial Data” for periods preceding the Merger and for the period succeeding the Merger are presented as the consolidated financial statements of the “Predecessor” and the “Successor”, respectively. The consolidated financial statements of the Predecessor have been prepared on the same basis as the audited financial statements included in EFC Holdings’ Annual Report for the year ended December 31, 2006 with the exception of the adoption of FIN 48, a change in presentation related to EFC Holdings’ adoption of FIN 39-1 and a change in classification to report the results of commodity hedging and trading activities on a separate line in the income statement instead of within operating revenues. (See Note 1 to the 2007 year-end and September 30, 2008 Financial Statements “Basis of Presentation.”) The consolidated financial statements also reflect the application of “purchase accounting” (for the Successor periods) and contributions of certain subsidiaries and net assets from EFH Corp. that were accounted for in a manner similar to a pooling of interests.

Quarterly Information (unaudited)

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


	Successor
	First Quarter			Second Quarter			Third Quarter
2008:
Operating revenues	$	1,983		$	2,567		$	3,258
Net income (loss)	$	(1,239	)	$	(3,289	)	$	3,586


	Predecessor(a)						Successor
	First Quarter		Second Quarter		Third Quarter		Period from October 11, 2007 through December 31, 2007
2007:
Operating revenues	$	2,003	$	2,049	$	2,572	$	1,671
Income (loss) from continuing operations		22		210		1,000		(1,266	)
Net income (loss)	$	22	$	210	$	1,000	$	(1,266	)

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


	Predecessor
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2006:
Operating revenues	$	2,054	$	2,362	$	3,030	$	1,950
Income from continuing operations		547		491		939		524
Net income	$	547	$	491	$	939	$	524

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

References to “EFC Holdings” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” refer to Energy Future Competitive Holdings Company and/or its subsidiaries, depending on context. See “Glossary” for other defined terms used in this prospectus.

Business

EFC Holdings is a wholly-owned subsidiary of EFH Corp. and is a Dallas-based holding company that conducts its operations principally through its wholly-owned subsidiary, TCEH. TCEH is a Dallas-based holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including Luminant, which is engaged in electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases and commodity risk management and trading activities, and TXU Energy, which is engaged in retail electricity sales. Commodity risk management and allocation of financial resources are performed at the consolidated level; therefore, there are no reportable business segments.

In connection with the Merger, which closed on October 10, 2007, certain wholly-owned subsidiaries of EFH Corp. established for the purpose of developing and constructing new generation facilities became subsidiaries of TCEH, and certain assets and liabilities of other such subsidiaries were transferred to TCEH and its subsidiaries. Those subsidiaries holding impaired construction work-in-process assets related to eight cancelled coal-fueled generation units did not become subsidiaries of TCEH. (In addition, a wholly-owned subsidiary of EFC Holdings representing a lease trust holding certain combustion turbines became a subsidiary of TCEH.) Because these transactions were between entities under the common control of EFH Corp., EFC Holdings accounted for the transactions in a manner similar to a pooling of interests. As a result, historical operations, financial position and cash flows of EFC Holdings and the entities and other net assets contributed are presented on a combined basis for all periods presented. See Note 4 to the 2007 year-end Financial Statements for additional information.

Significant Developments

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

The aggregate purchase price paid for the equity securities of EFH Corp. was $31.9 billion, which purchase price was funded by $8.3 billion of equity financing from the Sponsor Group and the Investors and by certain debt financings of TCEH described in Note 16 to the 2007 year-end Financial Statements and other debt financings of EFH Corp. This purchase price is exclusive of $0.8 billion in costs directly associated with the Merger, consisting of legal, consulting and professional service fees incurred by the Sponsor Group. See Note 1 to the 2007 year-end Financial Statements for additional details regarding the completion of the Merger.

The Merger was recorded under purchase accounting, whereby the total purchase price of the transaction was allocated to EFH Corp.’s identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values, and the excess of the purchase price over the fair value of the net assets was recorded as goodwill. For EFH Corp., the allocation resulted in $22.9 billion of goodwill and $10.0 billion in increased or new net tangible and identifiable intangible assets. Purchase accounting impacts, including goodwill recognition, have been “pushed down”, resulting in the assets and liabilities of EFC Holdings being recorded at their respective fair values as of October 10, 2007 and the recording of $18.0 billion of goodwill by EFC Holdings. As of December 31, 2007, EFC Holdings had a consolidated principal amount of total debt (short-term borrowings and long-term debt, including amounts due currently) of $31.6 billion, excluding $198 million of unamortized discounts and including $2.250 billion of EFH Corp. Notes (see Note 7 to the September 30, 2008 Financial Statements).

Uncertain Financial Markets — While EFC Holdings believes its cash on hand and cash from operations combined with availability under its existing credit facilities provides sufficient liquidity to fund current obligations, projected working capital requirements and capital spending, there can be no assurance, considering the current uncertainty in financial markets, that counterparties to its credit facilities will perform as expected through the maturity dates and counterparties in the natural gas hedging program will meet their obligations, or that material unexpected changes in financial markets or the economy will not result in liquidity constraints or require increased funding, including related to pension and OPEB obligations. In light of current market conditions, EFC Holdings reviewed the quality of its investments in money market funds and determined there are no indications that these investments should be valued at less than carrying value at September 30, 2008.

Also see Note 3 to the September 30, 2008 Financial Statements regarding potential impairment of goodwill and Note 5 to the September 30, 2008 Financial Statements regarding a charge related to the filing by Lehman Brothers Holdings Inc. for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code, Note 14 to the September 30, 2008 Financial Statements for discussion of an investment in a money market fund that is being liquidated, and “Liquidity and Capital Resources” (below) for discussion of actions taken in response to the uncertain financial markets.

Long-Term Hedging Program — In October 2005, EFC Holdings initiated a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, subsidiaries of EFC Holdings have entered into market transactions involving natural gas-related financial instruments. As of October 24, 2008, these subsidiaries have effectively sold forward approximately 2.1 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 280,000 GWh at an assumed 7.5 MMBtu/MWh market heat rate) over the period from 2008 to 2014 at average annual sales prices ranging from $7.20 per MMBtu to $8.35 per MMBtu. EFC Holdings currently expects to hedge approximately 80% of the equivalent natural gas price exposure of its expected baseload generation output on a rolling five-year basis. For the period from 2008 to 2014, and taking into consideration the estimated portfolio impacts of TXU Energy’s retail electricity business, the hedging transactions described in the previous sentence result in EFC Holdings having effectively hedged approximately 77% of its expected baseload generation natural gas price exposure for such period (on an average basis for such period). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices. If market heat rates decline in the future, which would indicate a lessening of such correlation, EFC Holdings expects that the cash flows targeted under the long-term hedging program may not be achieved.

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

Prior to March 2007, a significant portion of the instruments under the long-term hedging program were designated and accounted for as cash flow hedges. In March 2007, these instruments were dedesignated as allowed under SFAS 133. Subsequent changes in the fair value of these instruments are being recorded as unrealized gains and losses in net income, which has and could continue to result in significantly increased volatility in reported net income. Based on the size of the long-term hedging program as of October 24, 2008, a $1.00/MMBtu change in natural gas prices across the period from 2008 through 2014 would result in the recognition by EFC Holdings of up to approximately $2.1 billion in pretax unrealized mark-to-market gains or losses.

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

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

Interest Rate Swap Transactions — See discussion in Note 7 to the September 30, 2008 Financial Statements regarding various interest rate swap transactions entered into since the Merger. As of September 30, 2008, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $16.55 billion principal amount of its senior secured debt maturing from 2009 to 2014. Taking into consideration these swap transactions, approximately 15% of EFC Holdings’ total long-term debt portfolio at September 30, 2008 was exposed to variable interest rate risk. In August 2008, swaps in effect at that time were dedesignated as cash flow hedges in accordance with SFAS 133, and subsequent changes in their fair value are being marked-to market in net income (reported in interest expense and related charges.) These swaps were designated as a result of the intent to change the variable interest rate terms of the hedged debt (from three-month LIBOR to one-month LIBOR) in connection with the planned execution of interest rate basis swaps to further reduce the fixed borrowing costs. In October 2008, TCEH entered into interest rate swaps that effectively fix the interest rates at between 7.5% and 7.6% on an additional $1 billion principal amount of the TCEH Senior Secured Facilities; these swaps will also be marked-to-market in net income. EFC Holdings may enter into additional interest rate swap transactions from time to time. The cumulative unrealized mark-to-market net losses

related to all interest rate swaps totaled $280 million at December 31, 2007 (all reported in accumulated other comprehensive income) and $404 million at September 30, 2008 ($431 million of which was reported in accumulated other comprehensive income) due to changes in market interest rates. These fair values can change materially as market conditions change.

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

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

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

Environmental Regulatory Matters — See discussion in Note 3 to the September 30, 2008 Financial Statements regarding the invalidation of the EPA’s Clean Air Interstate Rule and the related impairment of intangible assets representing NO _X and SO₂ emission allowances in the third quarter of 2008.

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

In September 2008, Luminant filed Part I of its loan guarantee application with the U.S. Department of Energy (DOE) for financing related to the proposed units. In December 2008, Luminant filed Part II of the application with the DOE.

Key Risks and Challenges

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

Natural Gas Price and Market Heat-Rate Exposure

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

In contrast to EFC Holdings’ natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating electricity from EFC Holdings’ nuclear and lignite/coal-fueled plants. All other factors being equal, these baseload generation assets, which provided 70% of EFC Holdings’ supply volumes in 2007, increase or decrease in value as natural gas prices rise or fall, respectively, because of the effect of natural gas prices setting marginal wholesale power prices in ERCOT.

With the exposure to variability of natural gas prices, retail sales price management and hedging activities are critical to the profitability of the business and maintaining consistent cash flow levels. With the expiration of the regulatory price-to-beat rate mechanism on January 1, 2007 (see discussion under “Regulation and Rates” included elsewhere in this prospectus), TXU Energy has price flexibility in all of its retail markets with the exception of the sales to customers on fixed rate plans.

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

EFC Holdings’ approach to managing commodity price risk focuses on the following:

•

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

•

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

•

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

•

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

As discussed above under “Significant Developments”, EFC Holdings has implemented a long-term hedging program to mitigate the risk of future declines in wholesale electricity prices due to declines in natural gas prices.

The following scenarios are presented to quantify the potential impact of movements in natural gas prices and market heat rates. Illustratively, if sales prices for which TXU Energy has price flexibility immediately and fully adjusted to reflect changes in wholesale electricity prices due to changes in natural gas prices, and taking into account the hedges in place at year-end 2007 under the long-term hedging program that were expected to settle in 2008, EFC Holdings could have experienced an approximate $170 million reduction in 2008 pretax earnings for every $1.00 per MMBtu reduction in natural gas prices (approximate 13% change in mid-March 2008 price) sustained over the full year. In the same scenario of full and immediate pass-through of wholesale electricity price changes to sales prices, where natural gas prices and other nonprice conditions remained unchanged but ERCOT wholesale electricity prices declined by $5/MWh (approximate 8% change in mid-March 2008 price) for a full year because of a decline in market heat rates, EFC Holdings could have experienced an approximate $260 million reduction in 2008 pretax earnings.

The long-term hedging program does not mitigate exposure to changes in market heat rates. EFC Holdings’ market heat rate exposure is derived from its generation portfolio and is potentially impacted by generation capacity increases, particularly increases in lignite/coal, nuclear and wind capacity, which could result in lower market heat rates. EFC Holdings expects that decreases in market heat rates would decrease the value of its generation assets because lower market heat rates generally result in lower wholesale electricity prices, and vice versa.

On an ongoing basis, EFC Holdings will continue monitoring its overall commodity risks and seek to balance its portfolio based on its desired level of exposure to natural gas prices and market heat rates and potential changes to its operational forecasts of overall generation and consumption in its native and growth business. Portfolio balancing may include the execution of incremental transactions, or the unwinding of existing transactions or the substitution of natural gas hedges with commitments for the sale of electricity at fixed prices or heat rate hedges. As a result, commodity price exposures and their effect on earnings could change from time to time.

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

Competitive Markets and Customer Retention

Competitive retail activity in Texas continued to result in declines in sales volumes through 2007 in EFH Corp.’s historical service territory. Total retail sales volumes declined 5%, 11% and 17% in 2007, 2006 and 2005, respectively, as retail sales volume declines in EFH Corp.’s historical service territory were partially offset by growth in other territories. While competition was a factor, the decline in 2007 also reflected unusually cool summer weather. The area representing EFH Corp.’s historical service territory prior to deregulation, largely in north Texas, consisted of more than 3 million electricity consumers (measured by meter counts) as of year-end 2007. TXU Energy currently has approximately 2.2 million retail customers in Texas. In responding to the competitive landscape and full competition in the ERCOT marketplace since January 1, 2007, TXU Energy is focusing on the following key initiatives:

•

Introducing competitive pricing initiatives;

•

Growing the retail customer base by actively competing for new and existing customers in areas in Texas open to competition. The customer retention strategy remains focused on delivering high quality customer service and improving the overall customer experience. In line with this strategy, TXU Energy continues to implement initiatives to improve customer service;

•

Establishing itself as one of the most innovative retailers in the Texas market and developing tailored product offerings to meet customer needs by, in part, investing $100 million over the five-year period beginning in 2008 in retail initiatives aimed at helping consumers conserve energy and other demand-side management initiatives that are intended to help reduce peak demand for electricity; and

•

Focusing on programs targeted to retain the existing highest-value business market customers and recapturing those business customers who have switched REPs, including a more disciplined contracting and pricing approach and improved economic segmentation of the business market to enhance targeted sales and marketing efforts and to more effectively deploy the direct-sales force. Tactical programs put into place include improved customer service, new product price/service offerings and a multichannel approach for certain business markets.

Substantial Leverage, Uncertain Financial Markets and Liquidity Risk

EFC Holdings’ substantial leverage, resulting in part from debt incurred to finance the Merger, will require a substantial amount of cash flow to be dedicated to principal and interest payments and could adversely affect

its ability to raise additional capital to fund operations, limit its ability to react to changes in the economy or its industry, expose it to interest rate risk to the extent of its variable rate debt and limit its ability to meet its obligations. EFC Holdings’ consolidated principal amount of total debt (representing short-term borrowings and long-term debt, including amounts due currently) at December 31, 2007 and September 30, 2008 was $31.6 billion and $34.5 billion, respectively, excluding unamortized discounts and including $2.250 billion of EFH Corp. Notes (See Note 16 to the 2007 year-end Financial Statements and Note 7 to the September 30, 2008 Financial Statements). In 2008, annual interest expense and related charges are expected to total approximately $2.6 billion. Taking into consideration interest rate swap transactions as of September 30, 2008, approximately 15% of EFC Holdings’ total long-term debt portfolio is exposed to variable interest rate risk. Principal payments on EFC Holdings’ debt in 2008 are expected to total approximately $160 million.

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

Texas Generation Development Program

The undertaking of the development of three generation facilities in Texas as described above under “Significant Developments” involves a number of risks. Aggregate cash capital expenditures to develop these three units are expected to total approximately $3.25 billion. While EFC Holdings believes the investment economics of the program are strong, estimates of future natural gas prices, market heat rates and effects of any CO₂ emissions regulation may prove to be inaccurate, and returns on the investment could be significantly less than anticipated. The program is exposed to construction delays, failure of the units to meet performance specifications, nonperformance by equipment suppliers, increases in construction labor costs (contractually limited in part), commissioning and start-up risks and other project execution risks. Further, project capital spending for the three units continues despite continued public discussion of the advantages and disadvantages of coal-fueled generation. Should these development activities be canceled, EFC Holdings would be exposed to impairment of construction work-in-process assets and project discontinuance costs, including equipment order cancellation penalties (see Note 17 to the 2007 year-end Financial Statements and Note 8 to the September 30, 2008 Financial Statements). Management has evaluated the potential risks and benefits of the program to both Texas consumers and EFC Holdings and believes that in consideration of the most likely market and performance scenarios, continued progress towards completion of the program is the appropriate course of action.

Energy Prices and Regulatory Risk

Natural gas prices rose to unprecedented levels in the latter part of 2005, reflecting a world-wide increase in energy prices compounded by hurricane-related infrastructure damage. The related rise in retail electricity prices elevated public awareness of energy costs and dampened customer demand in 2006 and 2007. Natural gas prices remain subject to events that create price volatility, and while not at 2005 levels, forward natural gas prices have risen substantially since the end of 2006 and have been especially volatile in 2008. Sustained high energy prices and/or ongoing price volatility also creates a risk for regulatory and/or legislative intervention with the mechanisms that govern the competitive wholesale and retail markets in ERCOT. EFC Holdings believes that competitive markets result in a broad range of innovative pricing and service alternatives to consumers and ultimately the most efficient use of resources, and that regulatory bodies should continue to take actions that encourage competition in the industry. Regulatory and/or legislative intervention could disrupt the relationship between natural gas prices and wholesale electricity prices, which could negatively impact results of EFC Holdings’ long-term hedging strategy.

New and Changing Environmental Regulations

EFC Holdings is subject to various environmental laws and regulations related to SO₂, NO_x and mercury emissions as well as other environmental contaminants that impact air and water quality. EFC Holdings is in compliance with all current laws and regulations, but regulatory authorities continue to evaluate existing requirements and consider proposals for changes. In addition, in July 2008, the US Court of Appeals for the DC Circuit (DC Circuit) invalidated the EPA’s Clean Air Interstate Rule (CAIR), which required reductions of SO₂ and NO_x emissions from power generation facilities in 28 states, including Texas, where EFC Holdings’ generation facilities are located and remanded CAIR to the EPA to promulgate a rule consistent with its opinion. In December 2008, in response to an EPA petition, the DC Circuit reversed, in part, its previous ruling. Such reversal confirmed CAIR’s invalidity, but allowed it to remain in place while the EPA revises CAIR to correct the previously identified shortcomings. Since the D.C. Circuit did not prescribe a deadline for this revision, at this time, EFC Holdings cannot predict how or when the EPA may revise CAIR. See Note 3 to the September 30, 2008 Financial Statements for discussion of impairment charges recorded as a result of the court’s original decision.

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

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

•

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

•

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

•

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

•

Investing $400 million over the five years beginning in 2008 in programs designed to encourage customer electricity demand efficiencies, including $100 million expected to be invested by TXU Energy; and

•

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

Exposures Related to Nuclear Asset Outages

EFC Holdings’ nuclear assets are comprised of two generation units at Comanche Peak, each with a capacity of 1,150 MW. The Comanche Peak plant represents approximately 13% of EFC Holdings’ total generation capacity. The nuclear generation units represent EFC Holdings’ lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage, the unfavorable impact to pretax earnings is estimated to be approximately $3.5 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 17 to the 2007 year-end Financial Statements and Note 8 to the September 30, 2008 Financial Statements.

The inherent complexities and related regulations associated with operating nuclear generation facilities result in environmental, regulatory and financial risks. The operation of nuclear generation facilities is complex and subject to continuing review and regulation by the NRC, covering, among other things, operations, maintenance, emergency planning, security, and environmental and safety protection. The NRC may implement changes in regulations that result in increased capital or operating costs, and it may require extended outages, modify, suspend or revoke operating licenses and impose fines for failure to comply with its existing regulations and the provisions of the Atomic Energy Act. In addition, an unplanned outage at another nuclear generation facility could result in the NRC taking action to shut down the Comanche Peak plant as a precautionary measure.

The Comanche Peak plant has not experienced an extended unplanned outage, and management continues to focus on the safe, reliable and efficient operations at the plant.

Application of Critical Accounting Policies

EFC Holdings’ significant accounting policies are discussed in Note 1 to the 2007 year-end Financial Statements and Note 1 to the September 30, 2008 Financial Statements. EFC Holdings follows accounting principles generally accepted in the U.S. Application of these accounting policies in the preparation of EFC Holdings’ consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain critical accounting policies of EFC Holdings that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.

Purchase Accounting

The Merger has been accounted for by EFH Corp. under purchase accounting, whereby the purchase price of the transaction was allocated to EFH Corp.’s identifiable assets acquired and liabilities assumed based upon their fair values. The estimates of the fair values recorded were determined based on the principles in SFAS 157 (see Note 23 to the 2007 year-end Financial Statements and Note 12 to the September 30, 2008 Financial Statements) and reflect significant assumptions and judgments. Material valuation inputs for long-lived assets and liabilities included forward electricity and natural gas price curves and market heat rates, discount rates, nonperformance risk adjustments related to liabilities, retail customer attrition rates, generation plant operating and construction costs and asset lives. The valuations reflected considerations unique to the competitive wholesale power market in ERCOT as well as EFC Holdings’ assets. For example, the valuation of the baseload generation facilities considered EFC Holdings’ lignite fuel reserves and mining capabilities. Such assumptions and judgments that would be appropriate at the acquisition date may prove to be incorrect if market conditions change.

The results of the purchase price allocation included an increase in the total carrying value of EFC Holdings’ baseload generation plants and the recording of intangible assets related to the retail customer base, the TXU Energy trade name and emission credits. Further, commodity and other contracts not already subject to fair value accounting were valued, and amounts representing favorable or unfavorable contracts (versus market conditions as of the date of the Merger) were recorded as intangible assets or liabilities, respectively. Management believes all material intangible assets have been identified. See Notes 2 and 3 to the 2007 year-end Financial Statements and the September 30, 2008 Financial Statements for details of the purchase price allocation and intangible assets recorded, respectively.

The excess of the purchase price over the estimated fair values of the net assets acquired was recorded as goodwill. Purchase accounting impacts, including goodwill recognition, have been “pushed down”, resulting in the assets and liabilities of EFC Holdings being recorded at their fair values as of October 10, 2007. The assignment of purchase price was based on the relative estimated enterprise value of EFC Holdings’ operations as of the date of the Merger using discounted cash flow methodologies. In accordance with SFAS 142, goodwill is not amortized to net income, but is required to be tested for impairment at least annually. Management believes the drivers of the goodwill amount recorded by EFC Holdings 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. Also see discussion below under “Impairment of Long-Lived Assets”.

The purchase price allocation at September 30, 2008 is substantially complete; however, additional analysis with respect to the value of certain assets, contractual arrangements and contingent liabilities could result in a change in the total amount of goodwill and amounts recorded by EFC Holdings. See Note 2 to the 2007 year-end Financial Statements and the September 30, 2008 Financial Statements for details of the purchase price allocation.

Derivative Instruments and Mark-to-Market Accounting

EFC Holdings enters into contracts for the purchase and sale of energy-related commodities, and also enters into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Under SFAS 133, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.

Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. The default accounting treatment for a derivative is to record changes in fair value as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. EFC Holdings adopted SFAS 157 concurrent with the Merger and estimates fair value as described in Note 23 to the 2007 year-end Financial Statements and Note 12 to the September 30, 2008 Financial Statements.

SFAS 133 allows for “normal” purchase or sale elections and hedge accounting designations, which generally eliminates or defers the requirement for mark-to-market recognition in net income and thus reduces the volatility of net income that can result from fluctuations in fair values. These elections and designations are intended to better match the accounting recognition of the contract’s financial performance with the economic and risk decision-making profile. “Normal” purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting.

In accounting for cash flow hedges, changes in fair value are recorded in other comprehensive income with an offset to derivative assets and liabilities to the extent the change in value is effective; that is, it mirrors the offsetting change in fair value of the forecasted hedged transaction. Changes in value that represent ineffectiveness of the hedge are recognized in net income immediately, and the effective portion of changes in fair value are initially recorded in other comprehensive income and are recognized in net income in the period that the hedged transactions are recognized. EFC Holdings continually assesses its hedge elections and under SFAS 133 could dedesignate positions currently accounted for as cash flow hedges, the effect of which could be more volatility of reported earnings as all changes in the fair value of the positions would be included in net income. In March 2007, the instruments making up a significant portion of the long-term hedging program that were previously designated as cash flow hedges were dedesignated as allowed under SFAS 133. In addition, in August 2008, interest rate swap transactions in effect at that time were dedesignated as cash flow hedges in accordance with SFAS 133 and subsequent changes in their fair value are being marked-to-market in net income. See further discussion of the long-term hedging program and interest rate swap transactions above under “Significant Developments”.

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


	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			Year Ended December 31,
	Period from October 11, 2007 through December 31, 2007			Period from January 1, 2007 through October 10, 2007			2006			2005
Amounts recognized in net income (after-tax):
Unrealized net gains (losses) on positions marked-to-market in net income(a)	$	(955	)	$	(492	)	$	(2	)	$	22
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the period(a)		(56	)		(36	)		24			(16	)
Unrealized ineffectiveness net gains (losses) on positions accounted for as cash flow hedges	$	—			74			141			(24	)
Reversals of previously recognized unrealized net (gains) losses related to cash flow hedge positions settled in the period		—			(15	)		14			7

Total	$	(1,011	)	$	(469	)	$	177		$	(11	)

Amounts recognized in other comprehensive income (after-tax):
Net gains (losses) in fair value of positions accounted for as cash flow hedges(b)	$	(177	)	$	(288	)	$	598		$	(100	)
Net (gains) losses on cash flow hedge positions recognized in net income to offset hedged transactions(b)		—			(89	)		(47	)		125

Total	$	(177	)	$	(377	)	$	551		$	25

(a)

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

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

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


	Successor			Predecessor
	December 31, 2007			December 31, 2006
Net derivative asset related to commodity cash flow hedges	$	7		$	910
Net derivative liability related to interest rate cash flow hedges		(280	)		—
Net derivative liability related to interest rate fair value hedges		—			(4	)

Total net cash flow hedge and other derivative asset (liability)	$	(273	)	$	906

Net commodity contract asset (liability)(a)	$	(2,009	)	$	69

Long-term debt fair value adjustments—decrease in carrying value	$	—		$	10

Net accumulated other comprehensive gain (loss) included in shareholders’ equity (after-tax) amounts(b)	$	(177	)	$	430

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

(b)	All amounts included in other comprehensive income as of October 10, 2007, which totaled $53 million in net gains, were eliminated as part of purchase accounting.

Revenue Recognition

EFC Holdings’ 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 $445 million, $404 million, $406 million and $433 million at September 30, 2008, December 31, 2007, 2006 and 2005, respectively.

Accounting for Contingencies

The financial results of EFC Holdings may be affected by judgments and estimates related to loss contingencies. A significant contingency that EFC Holdings accounts for is the loss associated with uncollectible trade accounts receivable. The determination of such bad debt expense is based on factors such as historical write-off experience, aging of accounts receivable balances, changes in operating practices, regulatory rulings, general economic conditions and customers’ behaviors. Changes in customer count and mix due to competitive activity and seasonal variations in amounts billed add to the complexity of the estimation process. Historical results alone are not always indicative of future results, causing management to consider potential changes in customer behavior and make judgments about the collectibility of accounts receivable. Bad debt expense totaled $57 million, $13 million, $44 million, $67 million and $53 million for the nine months ended September 30, 2008, the period from October 11, 2007 to December 31, 2007, the period from January 1, 2007 to October 10, 2007, and the years ended December 31, 2006 and 2005, respectively.

Accounting for Income Taxes

EFH Corp. files a consolidated federal income tax return; however, EFC Holdings’ income tax expense and related balance sheet amounts are recorded as if the entity was a stand-alone corporation. EFC Holdings’ 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, EFC Holdings’ forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. EFH Corp.’s income tax returns are regularly subject to examination by applicable tax authorities. In management’s opinion, an adequate reserve has been made for any future taxes that may be owed as a result of any examination.

FIN 48 provides interpretive guidance for accounting for uncertain tax positions, and as discussed in Note 11 to the 2007 year-end Financial Statements, EFC Holdings adopted this new standard January 1, 2007. (See Notes 1 and 13 to the 2007 year-end Financial Statements and Note 14 to the September 30, 2008 Financial Statements for discussion of income tax matters.)

Impairment of Long-Lived Assets

EFC Holdings evaluates long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist, in accordance with SFAS 144. One of those indications is a current expectation that “more likely than not” a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. For EFC Holdings’ 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 EFC Holdings’ property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual plants that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing.

Goodwill and intangible assets with indefinite lives are required to be tested for impairment at least annually or whenever circumstances indicate an impairment may exist, such as the possible impairments to long-lived assets discussed above. EFC Holdings tests goodwill and intangible assets with indefinite lives for impairment on October 1^st each year. See Note 3 to the 2007 year-end and September 30, 2008 Financial Statements for additional discussion.

In 2006, EFC Holdings recorded an impairment charge of $198 million ($129 million after-tax) related to its natural gas-fueled generation units. See Note 9 to the 2007 year-end Financial Statements for a discussion of the impairment. The estimated impairment was based on numerous judgments including forecasted production, forward prices of natural gas and electricity, overall generation availability in ERCOT and ERCOT grid congestion.

Depreciation and Amortization

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

The estimated remaining lives range from 25 to 34 years for the lignite/coal-fueled generation units and an average 44 years for the nuclear-fueled generation units. The estimated life of these baseload units is 60 years, the same as estimates prior to purchase accounting. As of December 31, 2007, depreciation expense for the entire generation fleet was expected to total approximately $1.014 billion in 2008, an increase of $694 million over the annualized 2007 pre-Merger expense amount, reflecting the effects of the increased values pursuant to purchase accounting. See Note 1 to the 2007 year-end Financial Statements under “Property, Plant and Equipment” for discussion of the change from composite to asset-by-asset depreciation effective with the Merger.

Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 3 to the 2007 year-end Financial Statements and Note 3 to the September 30, 2008 Financial Statements for additional information.

Defined Benefit Pension Plans and OPEB Plans

Subsidiaries of EFC Holdings are participating employers in the pension plan sponsored by EFH Corp. and offer pension benefits through either a traditional defined benefit formula or a cash balance formula to eligible employees. Subsidiaries of EFC Holdings also participate in health care and life insurance benefit plans offered by EFH Corp. to eligible employees and their eligible dependents upon the retirement of such employees from EFC Holdings. Reported costs of providing noncontributory defined pension benefits and OPEBs are dependent upon numerous factors, assumptions and estimates.

Benefit costs are impacted by actual employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.

In accordance with accounting rules, changes in benefit obligations associated with these factors may not be immediately recognized as costs in the income statement, but are recognized in future years over the remaining average service period of plan participants. As such, significant portions of benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. Costs allocated from the plans are also impacted by movement of employees between participating companies. Pension and OPEB costs as determined under applicable accounting rules are summarized in the following table:


	Successor		Predecessor
	Period from October 11, 2007 through December 31, 2007		Period from January 1, 2007 through October 10, 2007		December 31,
					December 31,
					2006		2005
Pension costs under SFAS 87	$	1	$	4	$	8	$	33
OPEB costs under SFAS 106		2		9		10		59

Total benefit costs(a)		3		13		18		92
Less amounts deferred principally as a regulatory asset or property		—		—		—		(58	)

Net amounts recognized as expense	$	3	$	13	$	18	$	34

Funding of pension and OPEB Plans	$	—	$	1	$	1	$	48

(a)

Includes amounts capitalized as part of construction projects, which totaled approximately $14 thousand, $65 thousand, $48 thousand and $338 thousand for the period from October 11, 2007 through December 31, 2007, the period from January 1, 2007 through October 10, 2007, and for 2006 and 2005, respectively.

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

Pension and OPEB costs decreased $2 million in 2007 driven by a higher discount rate (5.90% from January 1, 2007 through October 10, 2007 and 6.45% from October 11, 2007 through December 31, 2007 versus 5.75% in 2006). Pension and OPEB costs decreased $74 million in 2006 primarily due to fewer employees, resulting from the distribution of Oncor to EFH Corp. in 2005, partially offset by a lower discount rate (5.75% in

2006 versus 6.00% in 2005) used to measure pension and OPEB obligations. Additional information regarding EFC Holdings’ pension and OPEB costs is provided in Note 21 to the 2007 year-end Financial Statements.

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

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

Presentation and Analysis of Results

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

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

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

Sales Volume and Customer Count Data


	Successor	Predecessor				Successor		Predecessor
	Three Months Ended September 30, 2008	Three Months Ended September 30, 2007		Change%		Nine Months Ended September 30, 2008		Nine Months Ended September 30, 2007	Change%
Sales volumes:
Retail electricity sales volumes—gigawatt hours (GWh):
Residential	9,098	8,789		3.5		22,153		21,256	4.2
Small business(a)	2,241	2,313		(3.1	)	5,802		5,861	(1.0	)
Large business and other customers	4,038	3,902		3.5		10,951		10,946	—

Total retail electricity	15,377	15,004		2.5		38,906		38,063	2.2
Wholesale electricity sales volumes	12,472	9,938		25.5		35,529		27,914	27.3
Net sales (purchases) of balancing electricity to/from ERCOT	145	(4	)	—		(1,335	)	622	—

Total sales volumes	27,994	24,938		12.3		73,100		66,599	9.8


	Successor		Predecessor				Successor		Predecessor
	Three Months Ended September 30, 2008		Three Months Ended September 30, 2007		Change%		Nine Months Ended September 30, 2008		Nine Months Ended September 30, 2007		Change%
Average volume (kWh) per retail customer(b):
Residential	4,757		4,764		(0.1	)	11,654		11,399		2.2
Small business	8,732		8,969		(2.6	)	22,578		22,421		0.7
Large business and other customers	145,802		109,115		33.6		361,554		276,764		30.6

Weather (service territory average)— percent of normal(c):
Percent of normal:
Cooling degree days	100.7	%	97.2	%			109.0	%	94.2	%
Heating degree days							93.7	%	106.2	%

Customer counts:
Retail electricity customers (end of period and in thousands)(d):
Residential							1,927		1,858		3.7
Small business(a)							258		256		0.8
Large business and other customers							27		35		(22.9	)

Total retail electricity customers							2,212		2,149		2.9

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

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

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

(d)	Based on number of meters.

Revenue and Market Share Data


	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Operating revenues:
Retail electricity revenues:
Residential	$	1,258		$	1,221		$	2,966		$	2,954
Small business(a)		335			335			852			849
Large business and other customers		447			368			1,143			1,025

Total retail electricity revenues		2,040			1,924			4,961			4,828
Wholesale electricity revenues		1,134			589			2,797			1,571
Net sales (purchases) of balancing electricity to/from ERCOT		(44	)		(19	)		(227	)		(11	)
Amortization of intangibles(b)		26			—			(15	)		—
Other operating revenues		102			78			293			236

Total operating revenues	$	3,258		$	2,572		$	7,809		$	6,624


	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Commodity hedging and trading activities:
Unrealized net gains (losses), including cash flow hedge ineffectiveness	$	6,068		$	479		$	(237	)	$	(695	)
Unrealized net gains (losses) representing reversals of previously recognized fair values of positions settled in the current period		20			—			(68	)		(8	)
Realized net gains (losses) on settled positions(c)		(43	)		(17	)		57			96

Net gain (loss)	$	6,045		$	462		$	(248	)	$	(607	)

Average revenues per MWh:
Residential	$	138.32		$	138.96		$	133.90		$	138.99
Estimated share of ERCOT retail markets(d)(e)(f):
Residential								37	%		36	%
Business markets								26	%		27	%

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

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

(c)

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

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

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

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

Production, Purchased Power and Delivery Cost Data


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended September 30, 2008		Three Months Ended September 30, 2007		Nine Months Ended September 30, 2008		Nine Months Ended September 30, 2007
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear	$	25	$	24	$	69	$	63
Lignite/coal		172		161		485		451

Total baseload fuel		197		185		554		514
Natural gas fuel and purchased power		1,161		559		2,532		1,377
Amortization of intangibles(a)		87		—		246		—
Other costs		94		57		304		203

Fuel and purchased power costs		1,539		801		3,636		2,094
Delivery fees		384		383		1,010		992

Total	$	1,923	$	1,184	$	4,646	$	3,086


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended September 30, 2008		Three Months Ended September 30, 2007		Nine Months Ended September 30, 2008		Nine Months Ended September 30, 2007
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	4.88	$	4.68	$	4.75	$	4.59
Lignite/coal(b)	$	15.39	$	14.18	$	15.83	$	14.31
Natural gas fuel and purchased power	$	104.02	$	63.71	$	91.55	$	62.29
Delivery fees per MWh	$	24.77	$	25.09	$	25.69	$	25.60

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

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


	Successor		Predecessor				Successor		Predecessor
	Three Months Ended September 30, 2008		Three Months Ended September 30, 2007		Change%		Nine Months Ended September 30, 2008		Nine Months Ended September 30, 2007		Change%
Production and purchased power volumes (GWh):
Nuclear	4,996		5,110		(2.2	)	14,448		13,664		5.7
Lignite/coal	12,240		12,353		(0.9	)	33,697		34,297		(1.7	)

Total baseload generation	17,236		17,463		(1.3	)	48,145		47,961		0.4
Natural gas-fueled generation	2,124		2,108		0.8		3,843		3,491		10.1
Purchased power	9,042		6,662		35.7		23,816		18,619		27.9

Total energy supply	28,402		26,233		8.3		75,804		70,071		8.2
Less line loss and power imbalances	408		1,295		(68.5	)	2,704		3,472		(22.1	)

Net energy supply volumes	27,994		24,938		12.3		73,100		66,599		9.8


Baseload capacity factors (%):
Nuclear	98.4	%	100.6	%	(2.2	)	95.6	%	90.8	%	5.3
Lignite/coal	95.0	%	95.8	%	(0.8	)	87.7	%	89.7	%	(2.2	)
Total baseload generation	95.5	%	97.2	%	(1.7	)	89.8	%	90.0	%	(0.2	)

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


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

Total operating revenues	$	3,258		$	2,572

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

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

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

•

Higher average pricing contributed $68 million to the revenue increase. Higher average retail pricing reflected higher prices in the business markets driven by higher natural gas prices, partially offset by an approximate $5 million effect of lower pricing in the residential customer market. Lower residential pricing reflected the effect of a five percent price discount in October 2007 to those residential customers in EFH Corp.’s historical service territory with month-to-month service plans and a rate equivalent to the former price-to-beat.

•

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

•

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

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

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

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

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

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

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

gas prices on unrealized mark-to-market valuations. Following is an analysis of activities for the three months ended September 30, 2008 and 2007:

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

•

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

•

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

•

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

Realized net losses totaling $43 million include:

•

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

•

$62 million in net gains related to trading positions.

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

•

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

•

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

Realized net losses totaling $17 million include:

•

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

•

$13 million in net losses related to trading positions.

Operating costs increased $20 million, or 14%, to $158 million in 2008. The increase reflects $16 million in higher maintenance costs related to the timing and scope of planned and unplanned outages in baseload generation facilities, $4 million in costs related to combustion turbines now being operated for TCEH’s own benefit, $4 million in higher property taxes and $4 million of expenses associated with operational readiness at the generation units under construction, partially offset by $7 million in costs in 2007 for utilization of SO₂ credits for the coal/lignite-fueled generation plants.

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

SG&A expenses increased $21 million, or 14%, to $172 million in 2008. The increase reflects:

•

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

•

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

•

$4 million in higher salaries in generation operations driven by construction development and reflecting the transfer of employees to Luminant who were previously assigned to generation plants being developed by other EFH Corp. subsidiaries.

Other income totaled $2 million in 2008 and $20 million in 2007. The 2007 amount includes $12 million of amortization of a deferred gain on sale of a business that was eliminated in purchase accounting. Other deductions totaled $531 million in 2008 and a net credit of $34 million in 2007. The 2008 amount includes $499 million in impairment charges related to NO_x and SO₂ environmental allowances intangible assets discussed in Note 3 to the September 30, 2008 Financial Statements and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which has filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code. The 2007 amount includes a $48 million reduction in the liability previously recorded for leases related to gas-fueled combustion turbines that EFC Holdings had ceased operating for its own benefit and a $10 million charge related to the termination of a railcar operating lease. See Note 5 to the September 30, 2008 Financial Statements for details of other income and deductions.

Interest income decreased $90 million to $20 million in 2008 reflecting lower average balances of notes/advances to parent.

Interest expense and related charges increased $530 million to $647 million in 2008. The increase reflects $476 million due to higher average borrowings driven by the Merger-related financings, and $114 million due to higher average interest rates, including a $36 million unrealized mark-to-market gain related to interest rate swaps and $4 million of amortization of debt fair value discount resulting from purchase accounting, partially offset by $60 million in increased capitalized interest.

Income tax expense on pretax income totaled $1.986 billion in 2008 and $499 million in 2007. The effective income tax rates increased to 35.6% in 2008 from 33.3% in 2007. The effective rates reflect the application of EFH Corp.’s statutory tax rate to the unrealized mark-to-market net losses in 2007 and 2008 and impairment of SO₂ and NO_x environmental allowances in 2008. The increase in the effective tax rate is driven by the effect of a higher lignite depletion benefit in 2007 on a smaller income base and the absence in 2008 of the production deduction due to forecasted net operating losses.

Net income increased $2.586 billion to $3.586 billion in 2008 driven by unrealized mark-to-market gains on positions in the long-term hedging program, partially offset by higher net interest expense, the impairment of environmental allowances intangible assets and the effects of purchase accounting.

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


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

Total operating revenues	$	7,809		$	6,624

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

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

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

•

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

•

Higher average pricing increased revenues by $26 million. Higher average retail pricing reflected higher prices in the business markets driven by higher natural gas prices, partially offset by an approximate $108 million effect of lower pricing in the residential customer market. Lower residential pricing reflected the effect of a six percent price discount in March 2007, an additional four percent price discount in June 2007 and another five percent price discount in October 2007 to those residential customers in EFC Corp.’s historical service territory with month-to-month service plans and a rate equivalent to the former price-to-beat.

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

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

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

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

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

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

•

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

•

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

•

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

Realized net gains totaling $57 million include:

•

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

•

$133 million in net gains related to trading positions.

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

•

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

•

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

•

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

•

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

Realized net gains totaling $96 million include:

•

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

•

$26 million in net gains related to trading positions.

Operating costs increased $50 million, or 11%, to $501 million in 2008. The increase reflects $36 million in higher maintenance costs related to the timing and scope of planned and unplanned outages in baseload generation facilities, $11 million in costs related to combustion turbines now being operated for TCEH’s own benefit, $10 million in higher property taxes and $5 million of expenses associated with operational readiness at the generation units under construction, partially offset by $7 million in costs in 2007 for utilization of SO₂ credits for the lignite/coal-fueled generation plants and $3 million in individually insignificant items.

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

SG&A expenses increased $56 million, or 13%, to $495 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;

•

$14 million in higher salaries in generation operations driven by construction development and reflecting the transfer of employees to Luminant who were previously assigned to generation plants being developed by other EFH Corp. subsidiaries, and

•

$16 million in higher retail customer bad debt expense.

Other income totaled $8 million in 2008 and $55 million in 2007. The 2007 amount includes $35 million of amortization of a deferred gain on sale of a business that was eliminated in purchase accounting. The 2007 amount also includes $7 million of royalty income and $6 million in penalties received due to nonperformance under a coal transportation agreement. Other deductions totaled $550 million in 2008 and a net credit of $20 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 the September 30, 2008 Financial Statements and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which has filed for bankruptcy under the U.S. Bankruptcy Code. The 2007 amount includes a $48 million reduction in the liability previously recorded for leases related to gas-fueled combustion turbines that EFC Holdings had ceased operating for its own benefit and a $10 million charge related to the termination of a railcar operating lease. See Note 5 to the September 30, 2008 Financial Statements for details of other income and deductions.

Interest income decreased $256 million to $44 million in 2008 reflecting lower average notes receivable/advances.

Interest expense and related charges increased by $1.642 billion to $1.957 billion in 2008. The increase reflects $1.324 billion due to higher average borrowings driven by the Merger-related financings, and $501 million due to higher average interest rates, including a $36 million mark-to-market gain related to interest rate swaps and $12 million of amortization of debt fair value discount resulting from purchase accounting, partially offset by $183 million in increased capitalized interest.

Income tax benefits on pretax losses totaled $493 million in 2008 and income tax expense on pretax income totaled $545 million in 2007. The 2007 amount includes a deferred tax benefit of $30 million related to an amendment of the Texas margin tax by the Texas legislature. Excluding the effect of this 2007 item, the effective income tax rates were 34.4% on a loss in 2008 compared to 32.4% on income in 2007. (The unusual deferred tax benefit in 2007 distorts the comparison; therefore it has been excluded for purposes of a more meaningful discussion). The effective rates reflect the application of EFH Corp.’s statutory tax rate to the unrealized mark-to-market net losses in 2007 and 2008 and the impairment of SO₂ and NO_x environmental allowances intangible assets in 2008. The increase in the effective tax rate is driven by the effect of a lower lignite depletion benefit in 2008 on a smaller income base and the absence in 2008 of the production deduction due to forecasted net operating losses. The impact on the rate is also due to the effect of the Texas margin tax on pretax losses in 2008, under which interest expense is not deductible.

Net income (loss) decreased $2.175 billion to a net loss of $943 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 decrease in unrealized mark-to-market losses on positions in the long-term hedging program.

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

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2008. The net changes in these assets and liabilities, excluding “other activity” as described below, represent the pretax effect of mark-to-market accounting on net income for positions in the commodity contract portfolio that are not subject to cash flow hedge accounting (see discussion below and in Note 10 to the September 30, 2008 Financial Statements). For the nine months ended September 30, 2008, this effect totaled $217 million in unrealized net losses, which represented $233 million in net losses from changes in fair value and $16 million in net gains representing reversals of previously recognized fair values of positions settled in the current period. These positions represent both economic hedging and trading activities.


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

Commodity contract net asset (liability) at end of period	$	(2,141	)

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

(b)

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

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

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

In addition to the effect on net income of recording unrealized mark-to-market gains and losses that are reflected in the table above, similar effects arise in the recording of unrealized ineffectiveness gains and losses associated with commodity-related positions accounted for as cash flow hedges. These effects on net income, which include reversals of previously recorded unrealized ineffectiveness gains and losses to offset realized gains and losses upon settlement, are included in net gain (loss) from commodity hedging and trading activities and reflected in the balance sheet as changes in commodity and other derivative contractual assets and liabilities (see Note 10 to the September 30, 2008 Financial Statements). The total pretax effect of recording unrealized gains and losses in net income related to commodity contracts under SFAS 133 is summarized as follows:


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

Total unrealized gains (losses) related to commodity contracts	$	6,142	$	479		$	(221	)	$	(703	)

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

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


Net commodity contract liability	$	(2,141	)
Net receipts of natural gas under physical swap transactions		33

Amount of net liability arising from recognition of fair values	$	(2,108	)

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


	Maturity dates of unrealized commodity contract liabilities at September 30, 2008
Source of fair value(a)	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(158	)	$	(89	)	$	(20	)	$	—		$	(267	)
Prices provided by other external sources		50			(808	)		(806	)		(75	)		(1,639	)
Prices based on models		(7	)		(53	)		(40	)		(102	)		(202	)

Total	$	(115	)	$	(950	)	$	(866	)	$	(177	)	$	(2,108	)

Percentage of total fair value		6	%		45	%		41	%		8	%		100	%

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

The “prices actively quoted” category reflects only exchange traded contracts for which active quotes are readily available. The “prices provided by other external sources” category represents forward commodity positions valued using prices for which over-the-counter broker quotes are available. Over-the-counter quotes for

power in ERCOT generally extend through 2012 and over-the-counter quotes for natural gas generally extend through 2015, depending upon delivery point. The “prices based on models” category contains the value of all over-the-counter traded options, valued using option pricing models. In addition, this category contains other contractual arrangements that may have forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. In many instances, these contracts can be broken down into their component parts and each component valued separately. Components valued as forward commodity positions are included in the “prices provided by other external sources” category. Components valued as options are included in the “prices based on models” category.

Comprehensive Income

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


	Successor			Predecessor			Successor			Predecessor
	Three Months Ended September 30, 2008			Three Months Ended September 30, 2007			Nine Months Ended September 30, 2008			Nine Months Ended September 30, 2007
Net increase (decrease) in fair value of cash flow hedges:
Commodities	$	(8	)	$	7		$	(7	)	$	(290	)
Financing — interest rate swaps		(131	)		—			(175	)		—

		(139	)		7			(182	)		(290	)

Derivative value net losses (gains) reported in net income that relate to hedged transactions recognized in the period:
Commodities		5			(11	)		7			(90	)
Financing — interest rate swaps		36			2			76			6

		41			(9	)		83			(84	)

Total loss effect of cash flow hedges reported in other comprehensive income	$	(98	)	$	(2	)	$	(99	)	$	(374	)

EFH Corp. has historically used, and expects to continue to use, derivative instruments that are effective in offsetting future cash flow variability in interest rates and energy commodity prices. Amounts in accumulated other comprehensive income include (i) the value of unsettled transactions accounted for as cash flow hedges (for the effective portion), based on current market conditions, and (ii) the value of dedesignated and terminated cash flow hedges at the time of such dedesignation, less amounts reclassified to earnings as the original hedged transactions are recognized, unless the hedged transactions become probable of not occurring. The effects of the hedge will be recorded in the statement of income as the hedged transactions are actually settled and affect earnings. Also see Note 10 to the September 30, 2008 Financial Statements.

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

Presentation and Analysis of Results

The accompanying statements of consolidated income and cash flows for 2007 are presented for two periods: January 1, 2007 through October 10, 2007 (Predecessor) and October 11, 2007 through December 31, 2007 (Successor), which relate to the period before the Merger and the period after the Merger, respectively. Management’s discussion and analysis of results of operations and cash flows has been prepared by comparing the

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

At the end of December 2005, EFC Holdings distributed the assets and liabilities of Oncor to EFH Corp. as discussed in Note 5 to the 2007 year-end Financial Statements. Therefore, the results of operations of Oncor are reflected in EFC Holdings’ financial information for 2005, but are not included in the 2006 or 2007 financial information.

The following tables present financial operating results for the Successor period from October 11, 2007 through December 31, 2007 and for the Predecessor periods from January 1, 2007 through October 10, 2007 and the nine months ended September 30, 2006.

Financial Results


	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Nine Months Ended September 30, 2006(a)
Operating revenues	$	1,671		$	6,884		$	7,446
Fuel, purchased power costs and delivery fees		(852	)		(3,209	)		(3,081	)
Net gain (loss) from commodity hedging and trading activities		(1,492	)		(554	)		61
Operating costs		(124	)		(471	)		(441	)
Depreciation and amortization		(315	)		(253	)		(252	)
Selling, general and administrative expenses		(153	)		(452	)		(380	)
Franchise and revenue-based taxes		(30	)		(83	)		(86	)
Other income		2			59			46
Other deductions		(5	)		20			(205	)
Interest income		9			312			173
Interest expense and related charges		(652	)		(329	)		(257	)

Income (loss) from continuing operations before income taxes		(1,941	)		1,924			3,024
Income tax (expense) benefit		675			(618	)		(1,047	)

Income (loss) from continuing operations	$	(1,266	)	$	1,306		$	1,977

(a)

Reflects the effects of pooling of interests as discussed in Note 4 to the 2007 year-end Financial Statements, which resulted in no change in revenues, a decrease of $73 million in net gain from commodity hedging and trading activities and a decrease of $46 million in income from continuing operations.

Sales Volume and Customer Count Data


	Three Months Ended December 31, 2007			Predecessor						Predecessor
				Nine Months Ended September 30,						Year Ended December 31,
				2007			2006			2006			2005
Sales volumes:
Retail electricity sales volumes – gigawatt hours (GWh):
Residential		5,967			21,256			23,770			29,595			32,655
Small business (a)		1,622			5,861			6,716			8,424			9,678
Large business and other customers		3,591			10,946			10,703			14,031			15,843

Total retail electricity		11,180			38,063			41,189			52,050			58,176
Wholesale electricity sales volumes		11,198			27,914			25,870			36,931			52,001
Net sales (purchases) of balancing electricity to/from ERCOT (b)		47			622			1,268			874			4,787

Total sales volumes		22,425			66,599			68,327			89,855			114,964


Average volume (kWh) per retail customer (c):
Residential		3,197			11,399			12,235			15,359			15,825
Small business		6,337			22,421			23,926			30,360			32,078
Large business and other customers		104,582			276,764			210,515			285,277			243,538

Distribution volumes:
Electric energy delivered (GWh)		—			—			—			—			106,780

Weather (service territory average) – percent of normal (d):
Percent of normal:
Cooling degree days		—			94.2	%		118.5	%		117.6	%		107.0	%
Heating degree days		89.7	%		—			—			79.2	%		90.0	%

Average revenue per MWh:
Residential	$	127.87		$	138.99		$	148.44		$	147.43		$	117.86

Customer counts:
Retail electricity customers (end of period and in thousands) (e):
Residential		1,875			1,858			1,904			1,871			1,982
Small business (a)		256			256			273			267			288
Large business and other customers		33			35			47			44			55

Total retail electricity customers		2,164			2,149			2,224			2,182			2,325


Distribution points of delivery (end of period and in thousands):
Electricity distribution points of delivery (e)		—			—			—			—			3,013

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

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

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

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

(e)	Based on number of meters.

Revenue and Commodity Hedging and Trading Activities


	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Nine Months Ended September 30, 2006			Year Ended December 31,
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Nine Months Ended September 30, 2006			2006			2005
Operating revenues:
Retail electricity revenues:
Residential	$	654		$	3,064		$	3,528		$	4,363		$	3,849
Small business(a)		202			880			984			1,233			1,151
Large business and other customers		286			1,070			1,031			1,357			1,330

Total retail electricity revenues		1,142			5,014			5,543			6,953			6,330
Wholesale electricity revenues(b)		505			1,637			1,635			2,278			2,807
Net sales (purchases) of balancing electricity to/from ERCOT(b)		(9	)		(14	)		(6	)		(31	)		225
Amortization of intangibles(c)		(50	)		—			—			—			—
Transmission and delivery revenues		—			—			—			—			2,394
Other operating revenues(d)		83			247			274			196			354
Net intercompany eliminations		—			—			—			—			(1,286	)

Total operating revenues	$	1,671		$	6,884		$	7,446		$	9,396		$	10,824

Commodity hedging and trading activities:
Unrealized net gains (losses), including cash flow hedge ineffectiveness from changes in fair value(e)	$	(1,469	)	$	(646	)	$	203		$	228		$	2
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the current period(e)		(87	)		(76	)		11			44			(20	)
Realized net gains (losses) on settled positions(f)		64			168			(153	)		(119	)		(146	)

Total gain (loss)	$	(1,492	)	$	(554	)	$	61		$	153		$	(164	)

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

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

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

(d)	Includes a $162 million charge for a special customer appreciation bonus in 2006. This charge does not affect the computation of residential average revenues per MWh. See Note 10 to the 2007 year-end Financial Statements.

(e)

(f)

Includes physical commodity trading activity not subject to mark-to-market accounting of $3 million in net losses in the period October 11, 2007 to December 31, 2007, $16 million in net losses in the period January 1, 2007 to October 10, 2007, $29 million in net losses for the nine months ended September 30, 2006, $34 million in net losses for 2006 and $61 million in net gains for 2005.

Production, Purchased Power and Delivery Cost Data


	Successor		Predecessor
	Period from October 11, 2007 through December 31, 2007		Period From January 1, 2007 through October 10, 2007		Nine Months Ended September 30, 2006		Year Ended December 31,
	Period from October 11, 2007 through December 31, 2007		Period From January 1, 2007 through October 10, 2007		Nine Months Ended September 30, 2006		2006		2005
Fuel, purchased power costs and delivery fees ($ millions):
Nuclear fuel	$	21	$	66	$	65	$	85	$	78
Lignite/coal		127		467		353		475		475

Total baseload fuel		148		533		418		560		553
Natural gas fuel and purchased power		302		1,435		1,429		1,787		3,285
Amortization of intangibles (a)		67		—		—		—		—
Other costs		68		213		169		229		281

Fuel and purchased power costs (b)		585		2,181		2,016		2,576		4,119
Delivery fees		267		1,028		1,065		1,353		1,426
Intercompany eliminations (c)		—		—		—		—		(1,284	)

Total	$	852	$	3,209	$	3,081	$	3,929	$	4,261


	Three Months Ended December 31, 2007			Predecessor						Predecessor
				Nine Months Ended September 30,						Year Ended December 31,
				2007			2006			2006			2005
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:
Nuclear fuel	$	4.64		$	4.59		$	4.25		$	4.29		$	4.23
Lignite/coal(d)	$	13.48		$	14.31		$	11.60		$	11.73		$	11.68
Natural gas fuel and purchased power	$	60.04		$	62.29		$	65.71		$	62.99		$	60.37
Delivery fees per MWh	$	26.64		$	25.60		$	25.60		$	25.71		$	24.20
Production and purchased power volumes (GWh):
Nuclear		5,157			13,664			15,292			19,795			18,371
Lignite/coal		12,197			34,297			34,252			45,579			45,933

Total baseload generation		17,354			47,961			49,544			65,374			64,304
Natural gas-fueled generation		500			3,491			3,487			3,989			3,504
Purchased power (b)		5,483			18,619			18,258			24,380			50,920

Total energy supply		23,337			70,071			71,289			93,743			118,728
Less line loss and power imbalances		912			3,472			2,962			3,888			3,764

Net energy supply volumes		22,425			66,599			68,327			89,855			114,964

Baseload capacity factors (%):
Nuclear		101.6	%		90.8	%		102.0	%		98.8	%		91.5	%
Lignite/coal		94.5	%		89.7	%		89.5	%		89.1	%		89.8	%
Total baseload		96.5	%		90.0	%		93.1	%		91.8	%		90.3	%

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

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

(c)	Delivery fees charges from Oncor to TCEH of $1.284 billion in 2005 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.

Financial Results — 2007

Operating revenues are shown in the following table:


	Successor			Predecessor
	Period from October 11, 2007 through December 31, 2007			Period From January 1, 2007 through October 10, 2007			Nine Months Ended September 30, 2006
Total retail electricity revenues	$	1,142		$	5,014		$	5,543
Wholesale electricity revenues		505			1,637			1,635
Wholesale balancing activities		(9	)		(14	)		(6	)
Amortization of intangibles(a)		(50	)		—			—
Other operating revenues		83			247			274

Total operating revenues	$	1,671		$	6,884		$	7,446

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

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

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

•

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

•

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

•

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

The decrease in retail electricity revenues was partially offset by $186 million in revenues attributable to the ten additional days in the 2007 period compared to the 2006 period.

Wholesale electricity revenues increased $2 million. $66 million of revenue in 2007 was attributable to the ten additional days in the period compared to the 2006 period. For the nine month periods, wholesale electricity revenues reflected lower prices as average wholesale prices declined approximately 11% reflecting lower natural gas prices during 2007, the effect of which was partially offset by volume growth of 8% due in part to the decline in retail sales volumes associated with competitive activity.

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

Fuel, purchased power costs and delivery fees increased $128 million, or 4%, to $3.209 billion, with $123 million of the increase attributable to the ten additional days in the 2007 period compared to the 2006 period. As a percentage of revenue, fuel, purchased power costs and delivery fees were 47% in the 2007 period compared

to 41% in the 2006 period. The change reflected increased purchases of power due to a scheduled refueling and major maintenance outage for one of the two Comanche Peak nuclear units and higher lignite mining costs due to inefficiencies caused by significantly above normal summer rainfall.

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

•

$536 million in net losses related to hedge positions, which includes $498 million in net losses from changes in fair values and $38 million in net losses that represent reversals of previously recorded fair values of positions settled in the period. These losses are driven by the effect of higher natural gas prices in forward periods on positions in the long-term hedging program;

•

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

•

$75 million in net losses related to trading positions, which includes $58 million in net losses from changes in fair values and $17 million in net losses that represent reversals of previously recorded fair values of positions settled in the period;

•

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

•

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

Realized net gains totaling $168 million include:

•

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

•

$43 million in net gains related to trading positions.

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

•

$52 million in net losses related to hedge positions, which includes $10 million in net losses from changes in fair values and $42 million in net losses that represent reversals of previously recorded fair values of positions settled in the period. These losses are driven by the effect of higher natural gas prices in forward periods on positions in the long-term hedging program;

•

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

•

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

•

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

Realized net losses totaling $153 million include:

•

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

•

$51 million in net losses related to trading positions.

Operating costs increased $30 million, or 6%, to $471 million in 2007. Approximately $20 million of the increase was attributable to the ten additional days in the 2007 period compared to the 2006 period. The remaining increase reflected $18 million in higher generation maintenance costs largely due to the scheduled outage in the spring of 2007 of one of the Comanche Peak nuclear generation units and $7 million for the utilization of SO₂ emission credits in 2007 for the lignite/coal-fueled generation units, partially offset by lower costs largely resulting from generation technical support outsourcing service agreements.

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

SG&A expenses increased $70 million, or 18%, to $452 million in 2007. $13 million of the increase was attributable to the ten additional days in the 2007 period compared to the 2006 period. The remaining increase reflected $27 million in increased retail marketing expenses and $14 million in higher professional fees primarily for retail billing and customer care systems enhancements and marketing/strategic projects. The increase was also due to higher salary and benefit costs primarily driven by an increase in staffing in retail operations and higher costs due to reallocation of Capgemini outsourcing fees. Partially offsetting the increase in SG&A expenses were lower bad debt expenses driven by a decrease in delinquencies and lower accounts receivable balances.

Other income totaled $59 million in 2007 and $46 million in 2006. Other deductions totaled a credit of $20 million in 2007 and charges of $205 million in 2006. The 2007 amount includes:

•

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

•

a $48 million credit from reducing a liability previously recorded for leases related to gas-fueled combustion turbines that EFH Corp. ceased operating for its own benefit (see Note 7 to the 2007 year-end Financial Statements).

The 2006 amount includes a $198 million charge related to the write-down of natural gas-fueled generation units to fair value (see Note 9 to the 2007 year-end Financial Statements.) See Note 14 to the 2007 year-end Financial Statements for details of other income and deductions.

Interest income increased $139 million to $312 million in 2007 reflecting higher average advance balances and higher average rates on advances to affiliates.

Interest expense and related charges increased by $72 million to $329 million in 2007. $13 million of the increase was attributable to the ten additional days in the 2007 period compared to the 2006 period. The remaining increase of $59 million reflected $44 million due to higher average borrowings and $19 million due to higher average interest rates, partially offset by $4 million in increased capitalized interest.

Income tax expense totaled $618 million in 2007 compared to $1.047 billion in 2006. Excluding the $35 million deferred tax benefit in 2007 and the $44 million deferred tax charge in 2006 related to the Texas margin tax as described in Note 13 to the 2007 year-end Financial Statements, the effective income tax rate was 33.9% in 2007 and 33.2% in 2006. (These unusual deferred tax adjustments distort the comparison; they have therefore been excluded for purposes of a more meaningful discussion.)

Results from continuing operations decreased $671 million to $1.306 billion in 2007 driven by unrealized mark-to-market losses on positions in the long-term hedging program and lower other deductions.

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

Operating revenues for the Successor period of 2007 totaled $1.671 billion. Retail electricity revenues of $1.142 billion were impacted by lower average pricing driven by a five percent price discount effective with meter reads on October 24, 2007 to those residential customers in EFH Corp.’s historical service territory with month-to-month service plans and a rate equivalent to the former price-to-beat rate. Wholesale electricity revenues of $505 million reflect lower prices resulting from lower natural gas prices in 2007.

Fuel, purchased power costs and delivery fees for the Successor period of 2007 totaled $852 million or 51% of revenues. This amount included $67 million of net expense representing amortization of the intangible net asset values of emission credits, coal purchase contracts and power purchase agreements and the stepped-up value of nuclear fuel resulting from purchase accounting.

Net losses from commodity hedging and trading activities totaled $1.492 billion and reflected the following:

Unrealized mark-to-market net losses of $1.556 billion include:

•

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

•

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

•

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

TXU Energy Solutions Co LLC S-1