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EX-12 - COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - Energy Future Competitive Holdings Co LLCdex12.htm
EX-32.(A) - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECTION 906 - Energy Future Competitive Holdings Co LLCdex32a.htm
EX-99.(B) - TCEH COMPANY LLC CONSOLIDATED ADJUSTED EBITDA RECONCILIATION - Energy Future Competitive Holdings Co LLCdex99b.htm
EX-31.(B) - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECTION 302 - Energy Future Competitive Holdings Co LLCdex31b.htm
EX-31.(A) - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECTION 302 - Energy Future Competitive Holdings Co LLCdex31a.htm
EX-99.(C) - EFH CORP. CONSOLIDATED ADJUSTED EBITDA RECONCILIATION - Energy Future Competitive Holdings Co LLCdex99c.htm
EX-32.(B) - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECTION 906 - Energy Future Competitive Holdings Co LLCdex32b.htm
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

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

For the fiscal year ended December 31, 2010

— OR—

 

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

Commission File Number 333-153529-02

Energy Future Competitive Holdings Company

(Exact name of registrant as specified in its charter)

 

Texas   75-1837355

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

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

 

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of Each Class

 

Name of Each Exchange in

Which Registered

Guaranty of Energy Future Holdings Corp.

9.75% Senior Secured Notes due 2019

  New York Stock Exchange

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

 

 

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨ (The registrant is not currently required to submit such files.)

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

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

 

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

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

Common Stock Outstanding as of February 15, 2011: 2,062,768 Class A shares, without par value and 39,192,594 Class B shares, without par value.

Energy Future Competitive Holdings Company meets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and is therefore filing this report with the reduced disclosure format.

 

 

DOCUMENTS INCORPORATED BY REFERENCE

None

 

 

 


Table of Contents

TABLE OF CONTENTS

 

          Page  

Glossary

     iii   
PART I   

Items 1. and 2. BUSINESS AND PROPERTIES

     1   

Item 1A.

   RISK FACTORS      17   

Item 1B.

   UNRESOLVED STAFF COMMENTS      35   

Item 3.

   LEGAL PROCEEDINGS      36   

Item 4.

   (REMOVED AND RESERVED)      36   
PART II   
Item 5.    MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES      37   
Item 6.    SELECTED FINANCIAL DATA      38   
Item 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS      41   
Item 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK      82   
Item 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA      89   
Item 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE      162   
Item 9A.    CONTROLS AND PROCEDURES      162   
Item 9B.    OTHER INFORMATION      165   
PART III   
Item 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE      165   
Item 11.    EXECUTIVE COMPENSATION      165   
Item 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS      165   
Item 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE      165   
Item 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES      166   
PART IV   
Item 15.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES      168   

 

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Table of Contents

Energy Future Competitive Holdings Company’s (EFCH) annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the Energy Future Holdings Corp. website at http://www.energyfutureholdings.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. EFCH also from time to time makes available to the public, free of charge, on the Energy Future Holdings Corp. website certain financial statements of its wholly-owned subsidiary, Texas Competitive Electric Holdings Company LLC. The information on Energy Future Holdings Corp.’s website shall not be deemed a part of, or incorporated by reference into, this report on Form 10-K. Readers should not rely on or assume the accuracy of any representation or warranty in any agreement that EFCH has filed as an exhibit to this Form 10-K because such representation or warranty may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent the parties’ risk allocation in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes or may no longer continue to be true as of any given date.

This Form 10-K and other Securities and Exchange Commission filings of EFCH and its subsidiaries occasionally make references to EFH Corp., EFCH (or “the company”), TCEH, TXU Energy or Luminant when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.

 

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GLOSSARY

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

 

1999 Restructuring Legislation    Texas Electric Choice Plan, the legislation that restructured the electric utility industry in Texas to provide for retail competition
2009 Form 10-K    EFCH’s Annual Report on Form 10-K for the year ended December 31, 2009
Adjusted EBITDA    Adjusted EBITDA means EBITDA adjusted to exclude noncash items, unusual items and other adjustments allowable under certain debt arrangements of TCEH and EFH Corp. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. EFCH is providing TCEH’s and EFH Corp.’s Adjusted EBITDA in this Form 10-K (see reconciliations in Exhibits 99(b) and 99(c)) solely because of the important role that Adjusted EBITDA plays in respect of certain covenants contained in the debt arrangements. EFCH does not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with US GAAP. Additionally, EFCH does not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, EFCH’s presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.
ancillary services    Refers to services necessary to support the transmission of energy and maintain reliable operations for the entire transmission system.
baseload    Refers to the minimum constant level of electricity demand in a system, such as ERCOT, and/or to the electricity generation facilities or capacity normally expected to operate continuously throughout the year to serve such demand, such as EFCH’s nuclear and lignite/coal-fueled generation units.
CAIR    Clean Air Interstate Rule
Capgemini    Capgemini Energy LP, a provider of business support services to EFCH and its subsidiaries
CATR    Clean Air Transport Rule
CFTC    Commodity Futures Trading Commission
CO2    carbon dioxide
DOE    US Department of Energy
EBITDA    Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. See the definition of Adjusted EBITDA above.

 

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EFCH    Refers to Energy Future Competitive Holdings Company, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of TCEH, and/or its subsidiaries, depending on context.
EFH Corp.    Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include TCEH and Oncor.
EFH Corp. Senior Notes    Refers collectively to EFH Corp.’s 10.875% Senior Notes due November 1, 2017 (EFH Corp. 10.875% Notes) and EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes).
EFH Corp. Senior Secured Notes    Refers collectively to EFH Corp.’s 9.75% Senior Secured Notes due October 15, 2019 (EFH Corp. 9.75% Notes) and EFH Corp.’s 10.000% Senior Secured Notes due January 15, 2020 (EFH Corp. 10% Notes).
EFIH    Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.
EFIH Finance    Refers to EFIH Finance Inc., a direct, wholly-owned subsidiary of EFIH, formed for the sole purpose of serving as co-issuer with EFIH of certain debt securities.
EPA    US Environmental Protection Agency
EPC    engineering, procurement and construction
ERCOT    Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas
ERISA    Employee Retirement Income Security Act of 1974, as amended
FASB    Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting
FERC    US Federal Energy Regulatory Commission
GAAP    generally accepted accounting principles
GHG    greenhouse gas
GWh    gigawatt-hours
IRS    US Internal Revenue Service
kWh    kilowatt-hours
Lehman    Refers to certain subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code in 2008.

 

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LIBOR    London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market.
Luminant    Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.
market heat rate    Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors.
Merger    The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007
Merger Agreement    Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.
Merger Sub    Texas Energy Future Merger Sub Corp, a Texas corporation and a wholly-owned subsidiary of Texas Holdings that was merged into EFH Corp. on October 10, 2007
MMBtu    million British thermal units
Moody’s    Moody’s Investors Services, Inc. (a credit rating agency)
MW    megawatts
MWh    megawatt-hours
NERC    North American Electric Reliability Corporation
NOx    nitrogen oxide
NRC    US Nuclear Regulatory Commission
NYMEX    Refers to the New York Mercantile Exchange, a physical commodity futures exchange.
Oncor    Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities.

 

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Oncor Holdings    Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context.
OPEB    other postretirement employee benefits
PUCT    Public Utility Commission of Texas
PURA    Texas Public Utility Regulatory Act
purchase accounting    The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
REP    retail electric provider
RRC    Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas
S&P    Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies Inc. (a credit rating agency)
SEC    US Securities and Exchange Commission
Securities Act    Securities Act of 1933, as amended
SG&A    selling, general and administrative
SO2    sulfur dioxide
Sponsor Group    Refers collectively to the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman Sachs & Co. (See Texas Holdings below.)
TCEH    Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of EFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy markets activities. Its major subsidiaries include Luminant and TXU Energy.
TCEH Finance    Refers to TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities.
TCEH Senior Notes    Refers collectively to TCEH’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015 Series B (collectively, TCEH 10.25% Notes) and TCEH’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes).

 

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TCEH Senior Secured Facilities    Refers collectively to the TCEH Initial Term Loan Facility, TCEH Delayed Draw Term Loan Facility, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 8 to Financial Statements for details of these facilities.
TCEH Senior Secured Second Lien Notes    Refers collectively to TCEH’s 15% Senior Secured Second Lien Notes due April 1, 2021 and TCEH’s 15% Senior Secured Second Lien Notes due April 1, 2021, Series B.
TCEQ    Texas Commission on Environmental Quality
Texas Holdings    Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.
Texas Holdings Group    Refers to Texas Holdings and its direct and indirect subsidiaries other than Oncor Holdings and its subsidiaries.
TRE    Refers to Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and ERCOT protocols.
TXU Energy    Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT.
US    United States of America
VIE    variable interest entity

 

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PART I

Items 1. and 2. BUSINESS AND PROPERTIES

See “Glossary” on page iii for defined terms and abbreviations.

EFCH’s Business and Strategy

EFCH, a wholly-owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company that conducts its operations almost entirely 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 electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities and retail electricity sales. Key management activities, including commodity risk management, are performed on an integrated basis; consequently, there are no reportable business segments.

TCEH owns or leases 15,427 MW of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas-fueled generation facilities. This capacity includes two new lignite-fueled units that achieved substantial completion (as defined in the EPC agreements for the units) in the fourth quarter 2009 and a third new lignite-fueled unit that achieved substantial completion (as defined in the EPC agreement for the unit) in the second quarter 2010. In addition, TCEH is the largest purchaser of wind-generated electricity in Texas and the fifth largest in the US. TCEH provides competitive electricity and related services to approximately two million retail electricity customers in Texas.

As of December 31, 2010, EFCH had approximately 5,100 full-time employees, including approximately 2,100 employees under collective bargaining agreements.

EFCH’s Market

EFCH operates primarily within the ERCOT market. This market represents approximately 85% of the 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 300 corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, investor-owned utilities, REPs and consumers.

The ERCOT market operates under reliability standards set by the NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure adequacy and reliability of power supply across Texas’s main interconnected transmission grid. The ERCOT independent system operator is responsible for procuring energy on behalf of its members while maintaining reliable operations of the electricity supply system in the market. Its responsibilities include centralized dispatch of the power pool and ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. 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.

Significant changes in the operations of the wholesale electricity market resulted from the change from a zonal to a nodal market implemented by ERCOT in December 2010. The nodal market design reflects a substantial increase in settlement price points for participants and establishes a new “day-ahead market,” operated by ERCOT, in which participants can enter into forward sales and purchases of electricity. The nodal market also establishes hub trading prices, which represent the average of node prices within geographic regions, at which participants can hedge and trade power through bilateral transactions. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events – Wholesale Market Design – Nodal Market” for additional discussion of the ERCOT nodal market.

 

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The following data is derived from information published by ERCOT:

Installed generation capacity in the ERCOT market estimated for 2011 totals approximately 85,000 MW, including approximately 3,000 MW mothballed (idled) capacity, as well as more than 10,000 MW of wind, water and other resources that may not be available coincident with system need. In August 2010, ERCOT’s hourly demand peaked at a record 65,776 MW. Of ERCOT’s estimate of total available capacity for 2011, approximately 60% is natural gas-fueled generation and approximately 28% is lignite/coal and nuclear-fueled baseload generation and approximately 12% in wind and other renewable resources. In November 2010, ERCOT changed its minimum reserve margin planning criterion to 13.75% from 12.5%; the reserve margin is projected by ERCOT to be 15.94% in 2011, 15.78% in 2012, and 13.14% by 2013. Reserve margin is the difference between system generation capability and anticipated peak load.

The ERCOT market has limited interconnections to other markets in the US, which currently limits potential imports into and exports out of the ERCOT market to 1,106 MW of generation capacity (or approximately 2% of peak demand). In addition, wholesale transactions within the ERCOT market are generally not subject to regulation by the FERC.

Natural gas-fueled generation is the predominant electricity capacity resource in the ERCOT market and accounted for approximately 39% of the electricity produced in the ERCOT market in 2010. Because of the significant natural gas-fueled capacity and the ability of such facilities to more readily increase or decrease production when compared to baseload generation, marginal demand for electricity is usually met by natural gas-fueled facilities. As a result, wholesale electricity prices in ERCOT largely correlate with natural gas prices.

EFCH’s Strategies

EFCH’s businesses focus operations on key safety, reliability, economic and environmental drivers such as optimizing and developing its generation fleet to safely provide reliable electricity supply in a cost-effective manner and in consideration of environmental impacts, hedging its electricity price risk and providing high quality service and innovative energy products to retail and wholesale customers.

Other elements of EFCH’s strategies include:

 

   

Increase value from existing business lines. EFCH’s strategy focuses on striving for top quartile or better performance across its operations in terms of safety, reliability, cost and customer service. In establishing tactical objectives, EFCH incorporates the following core operating principles:

 

   

Safety: Placing the safety of communities, customers and employees first;

 

   

Environmental Stewardship: Continuing to make strategic and operational improvements that lead to cleaner air, land and water;

 

   

Customer Focus: Delivering products and superior service to help customers more effectively manage their use of electricity;

 

   

Community Focus: Being an integral part of the communities in which EFCH employees live, work and serve;

 

   

Operational Excellence: Incorporating continuous improvement and financial discipline in all aspects of the business to achieve top-tier results that maximize the value of the company for stakeholders, including operating world-class facilities that produce and deliver safe and dependable electricity at affordable prices, and

 

   

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

 

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Pursue growth opportunities across business lines. Scale in EFCH’s 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. EFCH expects to also explore smaller-scale growth initiatives that are not expected to be material to its performance over the near term but can enhance its growth profile over time. Specific growth initiatives include:

 

   

Pursue generation development opportunities to help meet ERCOT’s growing electricity needs over the longer term from a diverse range of alternatives such as nuclear, renewable energy and advanced coal technologies.

 

   

Profitably increase the number of retail customers served throughout the competitive ERCOT market areas by delivering superior value through high quality customer service and innovative energy products, including leading energy efficiency initiatives and service offerings.

 

   

Reduce the volatility of cash flows through an electricity price risk management strategy. EFCH actively manages its exposure to wholesale electricity prices in ERCOT through contracts for physical delivery of electricity, exchange traded and “over-the-counter” financial contracts, ERCOT “day-ahead market” transactions and bilateral contracts with other wholesale market participants, including other generators and end-use customers. These hedging activities include shorter-term agreements, longer-term electricity sales contracts and forward sales of natural gas.

 

   

The strong historical correlation between natural gas prices and wholesale electricity prices in the ERCOT market provides EFCH an opportunity to manage its exposure to variability of wholesale electricity prices. EFCH has established a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments, and as of December 31, 2010, has effectively sold forward approximately 1.0 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 125,000 GWh at an assumed 8.0 market heat rate) for the period January 1, 2011 through December 31, 2014 at weighted average annual hedge prices ranging from $7.19 per MMBtu to $7.80 per MMBtu.

 

   

These transactions, as well as forward power sales, have effectively hedged an estimated 62% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning January 1, 2011 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will largely correlate with natural gas prices, which are expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If this correlation changes, the cash flows targeted under the long-term hedging program may not be achieved. As of December 31, 2010, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility), thereby reducing the cash and letter of credit collateral requirements for the hedging program. For additional discussion of the long-term hedging program, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” specifically sections entitled “Significant Activities and Events — Natural Gas Prices and Long-Term Hedging Program,” “Key Risks and Challenges — Natural Gas Price and Market Heat-Rate Exposure” and “Financial Condition – Liquidity and Capital Resources – Liquidity Effects of Commodity Hedging and Trading Activities.”

 

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Strengthen balance sheet through a liability management program. In 2009, EFH Corp. initiated a liability management program focused on improving EFH Corp.’s and its competitive subsidiaries’ (including EFCH’s) balance sheets. Accordingly, EFH Corp. and EFCH expect to opportunistically look for ways to reduce the amount, and extend the maturity, of their outstanding debt. The program has resulted in the capture of $700 million of debt discount for EFCH and the extension of $1.6 billion of maturities from 2015 to 2021. For EFH Corp., the program has resulted in the capture of $2.0 billion of debt discount (including the acquisition of $323 million principal amount of TCEH Senior Notes and $20 million principal amount of borrowings under the TCEH Senior Secured Facilities that are held as an investment by EFH Corp. or EFIH) and the extension of approximately $5.0 billion of maturities from 2014-2017 to 2019-2021. Activities to date have included debt exchanges, issuances and repurchases completed in 2010 and 2009 and the August 2009 amendment to the Credit Agreement governing the TCEH Senior Secured Facilities that provided additional flexibility in restructuring debt obligations. See Note 8 to Financial Statements for additional discussion of these transactions.

 

   

Future activities under the liability management program may include the purchase of EFCH’s outstanding debt for cash in open market purchases or privately negotiated transactions (including pursuant to a Section 10b-5(1) plan) or via public or private exchange or tender offers. Moreover, as part of the liability management program, EFCH may refinance its existing debt, including the TCEH Senior Secured Credit Facilities.

 

   

In evaluating whether to undertake any liability management transaction, including any refinancing, EFCH will take into account liquidity requirements, prospects for future access to capital, contractual restrictions, the market price of EFCH’s outstanding debt and other factors. Any liability management transaction, including any refinancing, may occur on a stand-alone basis or in connection with, or immediately following, other liability management transactions.

 

   

Pursue new environmental initiatives. EFCH is committed to continue to operate in compliance with all environmental laws, rules and regulations and to reduce its impact on the environment. EFH Corp.’s Sustainable Energy Advisory Board advises in the pursuit of technology development opportunities that reduce the company’s impact on the environment while balancing the need to help address the energy requirements of Texas. The Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, labor unions, customers, economic development in Texas and technology/reliability standards. In addition, EFCH is focused on and is pursuing opportunities to reduce emissions from its existing and new lignite/coal-fueled generation units. EFCH has voluntarily committed to reduce emissions of mercury, NOx and SO2 at its existing units. EFCH expects to make these reductions through a combination of investment in new emission control equipment, new coal cleaning technologies and optimizing fuel blends. In addition, EFCH expects to invest $100 million over a five-year period that began in 2008 in programs designed to encourage customer electricity demand efficiencies. As of December 31, 2010, EFCH had invested a cumulative total of $39 million in these programs.

Seasonality

EFCH’s revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.

Business Organization

Key TCEH management activities, including commodity price risk management and electricity sourcing for retail and wholesale customers, are performed on an integrated basis. However, for purposes of operational accountability, performance management and market identity, operations of TCEH have been grouped into Luminant, which is engaged in electricity generation and wholesale markets activities, and TXU Energy, which is engaged in retail electricity sales activities. These activities are conducted through separate legal entities.

 

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Luminant — Luminant’s existing electricity generation fleet consists of 14 plants in Texas with total installed nameplate generating capacity as shown in the table below:

 

Fuel Type

   Installed Nameplate
Capacity (MW)
     Number of Plants      Number of Units (a)  

Nuclear

     2,300         1         2   

Lignite/coal

     8,017         5         12   

Natural gas (b)(c)

     5,110         8         26   
                          

Total

     15,427         14         40   
                          

 

(a) Leased units consist of six natural gas-fueled combustion turbine units totaling 390 MW of capacity. All other units are owned.
(b) Includes 1,655 MW representing four units mothballed and not currently available for dispatch. See “Natural Gas-Fueled Generation Operations” below.
(c) Includes 1,268 MW representing eight units currently operated for unaffiliated parties.

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

Nuclear Generation Operations — Luminant operates two nuclear generation units at the Comanche Peak facility, each of which is designed for a capacity of 1,150 MW. Comanche Peak’s Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, and are generally operated at full capacity to meet the load requirements in ERCOT. Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, the refueling cycle results in the refueling of both units during the same year, which is planned for 2011 and last occurred in 2008. While one unit is undergoing a refueling outage, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance, modification and testing activities are completed that cannot be accomplished when the unit is in operation. Over the last three years the refueling outage period per unit has ranged from 19 to 26 days. The Comanche Peak facility operated at a capacity factor of 95% in 2008, reflecting refueling of both units and 100% in both 2009 and 2010.

Luminant has contracts in place for all of its uranium, nuclear fuel conversion services and nuclear fuel enrichment services for 2011. For the period of 2012 through 2018, Luminant has contracts in place for the acquisition of approximately 65% of its uranium requirements and 51% of its nuclear fuel conversion services requirements. In addition, Luminant has contracts in place for all of its nuclear fuel enrichment services through 2013, as well as all of its nuclear fuel fabrication services through 2018. Luminant does not anticipate any significant difficulties in acquiring uranium and contracting for associated conversion services and enrichment services in the foreseeable future.

Luminant believes its on-site used nuclear fuel storage capability is sufficient for a minimum of three years. The nuclear industry is continuing to review ways to enhance security of used-fuel storage with the NRC to fully utilize physical storage capacity. Future on-site used nuclear fuel storage capability will require the use of the industry technique of dry cask storage.

The Comanche Peak nuclear generation units have an estimated useful life of 60 years from the date of commercial operation. Therefore, assuming that Luminant receives 20-year license extensions, similar to what has been granted by the NRC to several other commercial generation reactors over the past several years, plant decommissioning activities would be scheduled to begin in 2050 for Comanche Peak Unit 1 and 2053 for Unit 2 and common facilities. Decommissioning costs will be paid from a decommissioning trust that, pursuant to state law, is funded from Oncor’s customers through an ongoing delivery surcharge. (See Note 14 to Financial Statements for discussion of the decommissioning trust fund.)

Nuclear insurance provisions are discussed in Note 9 to Financial Statements.

 

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

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

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

Lignite/Coal-Fueled Generation Operations — Luminant’s lignite/coal-fueled generation fleet capacity totals 8,017 MW (including three recently constructed new units) and consists of the Big Brown (2 units), Monticello (3 units), Martin Lake (3 units), Oak Grove (2 units) and Sandow (2 units) plants. These plants are generally operated at full capacity to help meet the load requirements in ERCOT, and maintenance outages are scheduled during seasonal off-peak demand periods. Over the last three years, the total annual scheduled and unscheduled outages per unit (excluding the three new units) averaged 33 days. Luminant’s lignite/coal-fueled generation fleet operated at a capacity factor of 87.6% in 2008, 86.5% in 2009 and 82.2% in 2010, which represents top quartile performance of US coal-fueled generation facilities. The 2008 performance reflects extended unplanned outages at several units, and the 2010 and 2009 performance reflects increased economic backdown of the units, reflecting short-term periods when wholesale electricity market prices were less than production costs.

Luminant recently completed the construction of three lignite-fueled generation units with a total capacity of 2,180 MW. The three units consist of one unit at a leased site that is adjacent to an existing lignite-fueled generation unit (Sandow) and two units at an owned site (Oak Grove). The Sandow unit and the first Oak Grove unit achieved substantial completion (as defined in the EPC agreements for the respective units) in the fourth quarter 2009. The second Oak Grove unit achieved substantial completion (as defined in the EPC agreement for the unit) in the second quarter 2010. Accordingly, Luminant has operational control of these units.

Aggregate cash capital expenditures for these three units totaled approximately $3.25 billion including all construction, site preparation and mining development costs. The investment included approximately $500 million for state-of-the-art emissions controls for the three new units. Including capitalized interest and the step-up in construction work-in-process balances to fair value as a result of purchase accounting for the Merger in 2007, carrying value of the units totaled approximately $4.8 billion upon completion.

Luminant also has an environmental retrofit program under which it plans to install additional environmental control systems at its existing lignite/coal-fueled generation facilities. Capital expenditures associated with these additional environmental control systems could exceed $1.0 billion, of which $377 million was spent through 2010. Luminant has not yet completed all detailed cost and engineering studies for the additional environmental systems, and the cost estimates could change materially as it determines the details of and further evaluates the engineering and construction costs related to these investments.

 

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Approximately 58% of the fuel used at Luminant’s lignite/coal-fueled generation plants in 2010 was supplied from lignite reserves owned in fee or leased surface-minable deposits dedicated to the Big Brown, Monticello, Martin Lake and Oak Grove plants, which were constructed adjacent to the reserves. Luminant owns in fee or has under lease an estimated 800 million tons of lignite reserves dedicated to its generation plants, including 246 million tons associated with an undivided interest in the lignite mine that provides fuel for the Sandow facility. Luminant also owns in fee or has under lease in excess of 85 million tons of reserves not currently dedicated to specific generation plants. In 2010, Luminant recovered approximately 27.5 million tons of lignite to fuel its generation plants. Luminant utilizes owned and/or leased equipment to remove the overburden and recover the lignite.

Luminant’s lignite mining operations include extensive reclamation activities that return the land to productive uses such as wildlife habitats, commercial timberland and pasture land. In 2010, Luminant reclaimed 1,729 acres of land. In addition, Luminant planted 1.2 million trees in 2010, the majority of which were part of the reclamation effort.

Luminant supplements its lignite fuel at Big Brown, Monticello and Martin Lake with western coal from the Powder River Basin in Wyoming. The coal is purchased from multiple suppliers under contracts of various lengths and is transported from the Powder River Basin to Luminant’s generation plants by railcar. Based on its current usage, Luminant believes that it has sufficient lignite reserves for the foreseeable future and has contracted more than 95% of its western coal resources and all of the related transportation through 2012.

Natural Gas-Fueled Generation Operations — Luminant’s fleet of 26 natural gas-fueled generation units totaling 5,110 MW of capacity includes 2,187 MW of currently available capacity, 1,268 MW of capacity being operated for unaffiliated third parties and 1,655 MW of capacity currently mothballed (idled). The natural gas-fueled units predominantly serve as peaking units that can be ramped up or down to balance electricity supply and demand.

Wholesale Operations — Luminant’s wholesale operations play a pivotal role in EFCH’s competitive business portfolio by optimally dispatching the generation fleet, including the baseload facilities, sourcing all of TXU Energy’s electricity requirements and managing commodity price risk associated with electricity sales and generation fuel requirements.

EFCH’s electricity price exposure is managed across the complementary Luminant generation and TXU Energy retail businesses on a portfolio basis. Under this approach, Luminant’s wholesale operations manage the risks of imbalances between generation supply and sales load, as well as exposures to natural gas price movements and market heat rate changes (variations in the relationships between natural gas prices and wholesale electricity prices), through wholesale market activities that include physical purchases and sales and transacting in financial instruments.

Luminant’s wholesale operations provide TXU Energy and other retail and wholesale customers with electricity and related services to meet their demands and the operating requirements of ERCOT. In consideration of operational production and customer consumption levels that can be highly variable, as well as opportunities for long-term purchases and sales with large wholesale market participants, Luminant buys and sells electricity in short-term transactions and executes longer-term forward electricity purchase and sales agreements. Luminant is the largest purchaser of wind-generated electricity in Texas and the fifth largest in the US with more than 900 MW of existing wind power under contract.

Fuel price exposure, primarily relating to Powder River Basin coal, natural gas and fuel oil and the transportation of the fuel, is managed primarily through short- and long-term contracts for physical delivery of fuel as well as financial contracts.

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

 

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The wholesale operations also dispatch Luminant’s available generation capacity. These dispatching activities result in economic backdown of lignite/coal-fueled units and ramping up and down of natural gas-fueled units as market conditions warrant. Luminant’s dispatching activities are performed through a centrally managed real-time operational staff that synthesizes operational activities across the fleet and interfaces with various wholesale market channels. In addition, the wholesale operations manage the fuel procurement requirements for Luminant’s fossil-fuel generation facilities.

Luminant’s wholesale operations include electricity and natural gas trading and third-party energy management activities. Natural gas transactions include direct purchases from natural gas producers, transportation agreements, storage leases and commercial retail sales. Luminant currently manages approximately 11 billion cubic feet of natural gas storage capacity.

Luminant’s wholesale operations manage exposure to wholesale commodity and credit-related risk within established transactional risk management policies, limits and controls. These policies, limits and controls have been structured so that they are practical in application and consistent with stated business objectives. Risk management processes include capturing transactions, performing and validating valuations and reporting exposures on a daily basis using risk management information systems designed to support a large transactional portfolio. A risk management forum meets regularly to ensure that business practices comply with approved transactional limits, commodities, instruments, exchanges and markets. Transactional risks are monitored to ensure limits comply with the established risk policy. Luminant has a disciplinary program to address any violations of the risk management policies and periodically reviews these policies to ensure they are responsive to changing market and business conditions.

TXU Energy — TXU Energy serves approximately two million residential and commercial retail electricity customers in Texas with approximately 62% of retail revenues in 2010 from residential customers. Texas is one of the fastest growing states in the nation with a diverse economy and, as a result, has attracted a number of competitors into the retail electricity market; consequently, competition is robust. TXU Energy, as an active participant in this competitive market, provides retail electric service to all areas of the ERCOT market now open to competition, including the Dallas/Fort Worth, Houston, Corpus Christi, and lower Rio Grande Valley areas of Texas. TXU Energy continues to market its services in Texas to add new customers and to retain its existing customers. There are approximately 120 active REPs certified to compete within the State of Texas. Based upon data published by the PUCT, as of September 30, 2010, approximately 53% of residential customers in competitive areas of ERCOT are served by REPs not affiliated with the pre-competition utility.

TXU Energy’s strategy focuses on providing its customers with high quality customer service and creating new products and services to meet customer needs; accordingly, a new customer management computer system was implemented in 2009, and other customer care enhancements are being implemented to further improve customer satisfaction. TXU Energy offers a wide range of residential products to meet various customer needs. TXU Energy is investing $100 million over the five-year period ending 2012, including a cumulative total of $39 million spent as of December 31, 2010, in energy efficiency initiatives as part of a program to offer customers a broad set of innovative energy products and services.

An affiliate of EFCH was recently certified by the Pennsylvania Public Utility Commission to sell retail electricity in Pennsylvania. While EFCH has made no commitments to enter markets outside of Texas, EFCH continuously monitors competitive retail markets for potential opportunities.

Regulation — Luminant is an exempt wholesale generator under the Energy Policy Act of 2005 and is subject to the jurisdiction of the NRC with respect to its nuclear generation plant. NRC regulations govern the granting of licenses for the construction and operation of nuclear-fueled generation facilities and subject such facilities to continuing review and regulation. Luminant also holds a power marketer license from the FERC and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior and any other competition-related rules and regulations under the Federal Power Act that are administered by the FERC.

 

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Luminant is also subject to the jurisdiction of the PUCT’s oversight of the competitive ERCOT wholesale electricity market. PUCT rules establish robust oversight certain limits and a framework for wholesale power pricing and market behavior. Luminant is also subject to the requirements of the ERCOT Protocols, including Nodal Protocols and ERCOT reliability standards as adopted and enforced by the TRE and the NERC, including NERC critical infrastructure protection (CIP) standards.

TXU Energy is a licensed REP under the Texas Electric Choice Act and is subject to the jurisdiction of the PUCT with respect to provision of electricity service in ERCOT. PUCT rules govern the granting of licenses for REPs, including oversight but not setting of prices charged. TXU Energy is also subject to the requirements of the ERCOT Protocols, including Nodal Protocols and ERCOT reliability standards as adopted and enforced by the TRE and the NERC, including NERC CIP standards.

Environmental Regulations and Related Considerations

Global Climate Change

Background — A growing concern has emerged nationally and internationally about global climate change and how greenhouse gas (GHG) emissions, such as CO2, might contribute to global climate change. EFCH produces GHG emissions from the direct combustion of fossil fuels at its generation plants, primarily its lignite/coal-fueled generation units. CO2, methane and nitrous oxide are emitted in this combustion process, with CO2 representing the largest portion of these GHG emissions. GHG emissions (primarily CO2) from combustion of fossil fuels represent the substantial majority of EFCH’s total GHG emissions. For 2010, EFCH estimates that its generation facilities produced 64 million short tons of CO2 based on continuously monitored data reported to and subject to approval by the EPA. Other aspects of EFCH’s operations result in emissions of GHGs including, among other things, coal piles at its generation plants, refrigerant from its chilling and cooling equipment, fossil fuel combustion in its motor vehicles and electricity usage at its facilities and headquarters. Because a substantial portion of EFCH’s generation portfolio consists of lignite/coal-fueled generation facilities, EFCH’s financial condition and/or results of operations could be materially adversely affected by the enactment of statutes or regulations that mandate a reduction in GHG emissions or that impose financial penalties, costs or taxes on those that produce GHG emissions. See Item 1A, “Risk Factors” for additional discussion of risks posed to EFCH regarding global climate change regulation.

Global Climate Change Legislation — Several bills have been introduced in the US Congress or advocated by the Obama Administration that are intended to address climate change using different approaches, including most prominently a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade). In addition to potential federal legislation to regulate GHG emissions, the US Congress might also consider other legislation that could result in the reduction of GHG emissions, such as the establishment of renewable or clean energy portfolio standards.

Through its own evaluation and working in tandem with other companies and industry trade associations, EFCH has supported the development of an integrated package of recommendations for the federal government to address the global climate change issue through federal legislation, including GHG emissions reduction targets for total US GHG emissions and rigorous cost containment measures to ensure that program costs are not prohibitive. In the event GHG legislation involving a cap-and-trade program is enacted, EFCH believes that such a program should be mandatory, economy-wide, consistent with expected technology development timelines and designed in a way to limit potential harm to the economy and protect consumers. EFCH believes that any mechanism for allocation of GHG emission allowances should include substantial allocation of allowances to offset the cost of GHG regulation, including the cost to electricity consumers. In addition, EFCH participates in a voluntary electric utility industry sector climate change initiative in partnership with the DOE. EFCH’s strategies are generally consistent with the “EEI Global Climate Change Points of Agreement” published by the Edison Electric Institute in January 2009 and “The Carbon Principles” announced in February 2008 by three major financial institutions. Finally, EFH Corp. has created a Sustainable Energy Advisory Board that advises EFCH on technology development opportunities that reduce the effects of its operations on the environment while balancing the need to address the energy requirements of Texas. EFH Corp.’s Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, customers, economic development in Texas and technology/reliability standards. If, despite these efforts, a substantial number of customers or others refuse to do business with EFCH because of its GHG emissions, it could have a material adverse effect on EFCH’s results of operations, financial position and liquidity.

 

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Federal Level — Recent developments in the US Congress indicate that the prospects for passage of any cap-and-trade legislation in the near-term are not likely. However, if such legislation were to be adopted, EFCH’s costs of compliance could be material.

In December 2009, the EPA issued a finding that GHG emissions endanger human health and the environment and that emissions from motor vehicles contribute to that endangerment. The EPA’s finding required it to begin regulating GHG emissions from motor vehicles and ultimately stationary sources under existing provisions of the federal Clean Air Act. Following its endangerment finding, the EPA took three regulatory actions with respect to the control of GHG emissions. First, in March 2010, the EPA completed a reconsideration of a memorandum issued in December 2008 by then EPA Administrator Stephen Johnson on the issue of when the Clean Air Act’s Prevention of Significant Deterioration (PSD) program would apply to newly identified pollutants such as GHG’s. The EPA determined that the Clean Air Act’s PSD permit requirements would apply when a nation-wide rule requiring the control of a pollutant takes effect. Under this determination, PSD permitting requirements became applicable to GHG emissions from planned stationary sources or planned modifications to stationary sources that had not been issued a PSD permit by January 2, 2011 – the first date that new motor vehicles must meet the new GHG standards. Second, in April 2010, the EPA adopted GHG emission standards for certain new motor vehicles. Third, in June 2010, the EPA finalized its so-called “tailoring rule” that established new thresholds of GHG emissions for the applicability of permits under the Clean Air Act for stationary sources, including EFCH’s power generation facilities. The EPA’s tailoring rule defines the threshold of GHG emissions for determining applicability of the Clean Air Act’s PSD and Title V permitting programs at levels greater than the emission thresholds contained in the Clean Air Act. In December 2010, the EPA announced agreements with state and environmental groups to propose New Source Performance Standards for electric power plants by July 2011 and to finalize those standards by May 2012. In addition, in September 2009, the EPA issued a final rule requiring the reporting, by March 2011, of calendar year 2010 GHG emissions from specified large GHG emissions sources in the US (such reporting rule would apply to EFCH’s lignite/coal-fueled generation facilities). If limitations on emissions of GHGs from existing sources are enacted, EFCH’s costs of compliance could be material.

In December 2010, in response to the State of Texas’s indication that it would not take regulatory action to implement the EPA’s tailoring rule, the EPA adopted a rule to take over the issuance of permits for GHG emissions from the Texas Commission on Environmental Quality (TCEQ). The State of Texas is challenging that rule and the GHG permitting rules through litigation and has refused to implement the GHG permitting rules issued by the EPA. A number of members of the US Congress from both parties have introduced legislation to either block or delay EPA regulation of GHGs under the Clean Air Act, and legislative activity in this area over the next year is possible.

In September 2009, the US Court of Appeals for the Second Circuit issued a decision in the case of State of Connecticut v. American Electric Power Company Inc. holding that various states, a municipality and certain private trusts have standing to sue and have sufficiently alleged a cause of action under the federal common law of nuisance for injuries allegedly caused by the defendant power generation companies’ emissions of GHGs. The decision does not address the merits of the nuisance claim. The US Supreme Court has agreed to review the Second Circuit’s decision.

In October 2009, the US Court of Appeals for the Fifth Circuit issued a decision in the case of Comer v. Murphy Oil USA reversing the district court’s dismissal of the case and holding that certain Mississippi residents did have standing to pursue state law nuisance, negligence and trespass claims for injuries purportedly suffered because the defendants’ emissions of GHGs allegedly increased the destructive force of Hurricane Katrina. The Fifth Circuit subsequently agreed to rehear the case, but then dismissed the appeal in its entirety when several judges recused themselves in the case. The Fifth Circuit’s order dismissing the appeal and vacating the earlier panel’s decision had the effect of reinstating the district court’s original dismissal of the case. In January 2011, the US Supreme Court rejected the plaintiffs’ request that their appeal be reinstated in the Fifth Circuit.

In September 2009, the US District Court for the Northern District of California issued a decision in the case of Native Village of Kivalina v. ExxonMobil Corporation dismissing claims asserted by an Eskimo village that emissions of GHGs from approximately 24 oil and energy companies are causing global warming, which has damaged the arctic sea ice that protects the village from winter storms and erosion. The court dismissed the claims because they raised political (not judicial) questions and because plaintiffs lacked standing to sue. An appeal of the district court’s decision is currently pending in the US Court of Appeals for the Ninth Circuit.

 

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While EFCH is not a party to these suits, they could encourage or form the basis for a lawsuit asserting similar nuisance claims regarding emissions of GHGs. If any similar suit is successfully asserted against EFCH in the future, it could have a material adverse effect on EFCH’s business, results of operations and financial condition.

State and Regional Level — There are currently no Texas state regulations in effect concerning GHGs, and there are no regional initiatives concerning GHGs in which the State of Texas is a participant. EFCH opposes state-by-state regulation of GHGs. In October 2009, Public Citizen Inc. filed a lawsuit against the TCEQ and its commissioners seeking to compel the TCEQ to regulate GHG emissions under the Texas Clean Air Act. The Attorney General of Texas has filed special exceptions to the Public Citizen pleading. EFCH is not a party to this litigation.

International Level — The US currently is not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC). The United Nations’ Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008 to 2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference, the Bali Action Plan was adopted, which identifies a work group, process and timeline for the consideration of possible post-2012 international actions to further address climate change. In December 2009, leaders of developed and developing countries met in Copenhagen under the UNFCCC and issued the Copenhagen Accord. The Copenhagen Accord provides a mechanism for countries to make economy-wide GHG emission mitigation commitments for reducing emissions of GHGs by 2020 and provides for developed countries to fund GHG emission mitigation projects in developing countries. President Obama participated in the development of, and endorsed, the Copenhagen Accord. In January 2010, the US informed the United Nations that it would reduce GHG emissions by 17% from 2005 levels by 2020, contingent on Congress passing climate change legislation.

EFCH continues to assess the risks posed by possible future legislative or regulatory changes pertaining to GHG emissions. Because some of the proposals described above are in their formative stages, EFCH is unable to predict the potential effects on its business, financial condition and/or results of operations; however, any such effects could be material. The effect will depend, in large part, on the specific requirements of the legislation or regulation and how much, if any, of the costs are included in wholesale electricity prices.

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

 

   

Investing in Energy Efficiency or Related Initiatives — EFCH expects to invest $100 million in BrightenSM energy saving solutions (energy efficiency) or related initiatives over a five-year period that began in 2008, including software- and hardware-based services deployed behind the meter. These programs leverage advanced meter interval data and in-home devices to provide usage and other information and insights to customers, as well as to control energy-consuming equipment. Examples of these initiatives include: the TXU Energy Electricity Usage Report, an electronic report which shows residential usage by week; the BrightenSM Personal Energy Advisor, an online energy audit tool with personalized tips and projects for saving electricity; the BrightenSM Online Energy Store that provides customers the opportunity to purchase hard-to-find, cost-effective energy-saving products; the BrightenSM Power Monitor, an in-home display device that enables residential customers to monitor whole-house energy usage and cost in real-time and projects month-end bill amounts; the BrightenSM iThermostat, a web-enabled programmable thermostat with a load control feature for cycling air conditioners during times of peak energy demand; time-based electricity rates that work in conjunction with advanced metering infrastructure; rate plans that include electricity from renewable resources; the BrightenSM Energy Efficiency Assistance Program that delivers products and services, as well as grants through social service agencies, to save energy at participating low income customer homes and apartment complexes; a program to refer customers to energy efficiency contractors, and the provision of rebates to business customers for purchasing new energy efficient equipment for their facilities through the Energy Efficiency Rebate Program;

 

   

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

 

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Promoting the Use of Solar Power — TXU Energy provides qualified customers, through its Solar Lease program, the ability to finance the addition of solar panels to their homes. TXU Energy also purchases surplus renewable distributed generation from qualified customers. In addition, TXU Energy’s Solar Academy works with Texas school districts to teach and demonstrate the benefits of solar power;

 

   

Investing in Technology — EFCH continues to evaluate the development and commercialization of cleaner power facility technologies; technologies that support sequestration and/or reduction of CO2; incremental renewable sources of electricity, including wind and solar power; energy storage, including advanced battery and compressed air storage, as well as related technologies that seek to lower emissions intensity. Additionally, EFCH continues to explore and participate in opportunities to accelerate the adoption of electric cars and plug-in hybrid electric vehicles that have the potential to reduce overall GHG emissions and is furthering the advance of such vehicles by supporting, and helping develop infrastructure for, networks of charging stations for electric vehicles;

 

   

Evaluating the Development of a New Nuclear Generation Facility — EFCH has filed an application with the NRC for combined construction and operating licenses for up to 3,400 MW of new nuclear generation capacity (the lowest GHG emission source of baseload generation currently available) at its Comanche Peak nuclear generation facility. In addition, EFCH has (i) filed a loan guarantee application with the DOE for financing of the proposed units and (ii) formed a joint venture with Mitsubishi Heavy Industries Ltd. (MHI) to further develop the units using MHI’s US-Advanced Pressurized Water Reactor technology, and

 

   

Offsetting GHG Emissions by Planting Trees — EFCH is engaged in a number of tree planting programs that offset GHG emissions, resulting in the planting of over 1.3 million trees in 2010. The majority of these trees were planted as part of EFCH’s mining reclamation efforts but also include TXU Energy’s Urban Tree Farm program, which has planted more than 165,000 trees since its inception in 2002.

Other Recent EPA Actions The EPA has recently completed several regulatory actions establishing new requirements for control of certain emissions from sources that include lignite/coal-fueled generation facilities. It is also currently considering several other regulatory actions, as well as contemplating future additional regulatory actions, (the more material of which are discussed further below) in each case that may affect EFCH’s lignite/coal-fueled generation facilities.

Each of EFCH’s lignite/coal-fueled generation facilities is currently equipped with substantial emissions control equipment, including equipment installed as part of EFCH’s commitment (in connection with the construction of the three recently completed lignite-fueled generation units) to reduce emissions of NOx, SO2 and mercury through the installation of emissions control equipment at both new and existing units and fuel blending at some existing units. All of EFCH’s lignite/coal-fueled generation facilities are equipped with activated carbon injection systems to reduce mercury emissions. Flue gas desulfurization systems designed primarily to reduce SO2 emissions are installed at Oak Grove Units 1 and 2, Sandow Units 4 and 5, Martin Lake Units 1, 2, and 3, and Monticello Unit 3. Selective catalytic reduction systems designed to reduce NOx emissions are installed at Oak Grove Units 1 and 2 and Sandow Unit 4. Selective non-catalytic reduction systems designed to reduce NOx emissions are installed at Sandow Unit 5, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Fabric filter systems designed primarily to reduce particulate matter emissions are installed at Oak Grove Units 1 and 2, Sandow Unit 5, Monticello Units 1 and 2, and Big Brown Units 1 and 2. Electrostatic precipitator systems designed primarily to reduce particulate matter emissions are installed at Sandow Unit 4, Martin Lake Units 1, 2, and 3, Monticello Units 1, 2, and 3, and Big Brown Units 1 and 2. Sandow Unit 5 uses a fluidized bed combustion process that facilitates control of NOx and SO2. Flue gas desulfurization systems, fabric filter systems, and electrostatic precipitator systems also assist in reducing mercury and other emissions.

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

 

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Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions

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

In 2005, the EPA issued a final rule to further reduce SO2 and NOx emissions from power plants. The SO2 and NOx reductions required under the Clean Air Interstate Rule (CAIR), which were required to be phased in between 2009 and 2015, were based on a cap and trade approach (market-based) in which a cap was put on the total quantity of emissions allowed in 28 eastern states (including Texas). Emitters were required to have allowances for each ton emitted, and emitters were allowed to trade emissions under the cap. In July 2008, the US Court of Appeals for the D.C. Circuit (D.C. Circuit Court) vacated CAIR. In December 2008, in response to an EPA petition, the D.C. Circuit Court reversed, in part, its previous ruling. Such reversal confirmed CAIR is not valid, but allowed it to remain in place while the EPA revises CAIR to correct the previously identified shortcomings. In July 2010, the EPA released a proposed rule called the Clean Air Transport Rule (CATR). The CATR, as proposed, would replace CAIR in 2012 and would require no additional emission reductions for Luminant. However, EFCH cannot predict the impact of a final rule on its business, results of operations and financial condition. See Note 2 to Financial Statements for discussion of the impairment of emission allowances intangible assets in 2008.

SO2 reductions required under the proposed regional haze/visibility rule (or so-called BART rule) only apply to units built between 1962 and 1977. The reductions are required on a unit-by-unit basis. In February 2009, the TCEQ submitted a State Implementation Plan (SIP) concerning regional haze to the EPA, which EFCH believes will not have a material impact on its generation facilities. The EPA has not made a decision on this SIP submittal.

The Clean Air Act requires each state to monitor air quality for compliance with federal health standards. The EPA is required to periodically review, and if appropriate, revise all national ambient quality standards. The standards for ozone are not being achieved in several areas of Texas. The TCEQ adopted SIP rules in May 2007 to deal with eight-hour ozone standards, which required NOx emission reductions from certain of EFCH’s peaking natural gas-fueled units in the Dallas-Fort Worth area. In March 2008, the EPA made the eight-hour ozone standards more stringent. In January 2010, the EPA proposed to further reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. Since the EPA projects that SIP rules to address attainment of these new more stringent standards will not be required until December 2013, EFCH cannot yet predict the impact of this action on its generation facilities. In January 2010, the EPA added a new one-hour NOx National Ambient Air Quality standard that may require actions within Texas to reduce emissions. The TCEQ will be required to revise its monitoring network and submit an implementation plan with compliance required no earlier than January 2021. In June 2010, the EPA adopted a new one-hour SO2 national ambient air quality standard that may require action within Texas to reduce SO2 emissions. The TCEQ will be required to conduct modeling and develop an implementation plan by 2014, pursuant to which compliance will be required by 2017, according to the EPA’s implementation timeline. EFCH cannot predict the impact of the new standards on its business, results of operations or financial condition until the TCEQ adopts (if required) an implementation plan with respect to the standards.

In 2005, the EPA also published a final rule requiring reductions of mercury emissions from lignite/coal-fueled generation plants. The Clean Air Mercury Rule (CAMR) was based on a nationwide cap and trade approach. The mercury reductions were required to be phased in between 2010 and 2018. In March 2008, the D.C. Circuit Court vacated CAMR. In February 2009, the US Supreme Court refused to hear the appeal of the D.C. Circuit Court’s ruling. The EPA agreed in a consent decree submitted for court approval to propose Maximum Achievable Control Technology rules by March 2011 and finalize those rules by November 2011. EFCH cannot predict the substance of any final EPA regulations on such hazardous air pollutants. However, the EPA has informally indicated that recently proposed regulations regarding hazardous air pollutants from industrial boilers may serve as a template for the forthcoming electricity generation unit regulations. The industrial boiler regulations, if applied to electricity generation units, would likely require material capital expenditures for additions to control equipment at EFCH’s lignite/coal-fueled generation facilities.

 

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In September 2010, the EPA disapproved a portion of the SIP pursuant to which the TCEQ implements its program to achieve the EPA’s National Ambient Air Quality Standards (NAAQS) under the Clean Air Act. The EPA disapproved the Texas standard permit for pollution control projects. EFCH holds several permits issued pursuant to the TCEQ standard permit conditions for pollution control projects. EFCH has challenged the EPA’s disapproval by filing a lawsuit in the US Court of Appeals for the Fifth Circuit arguing that the TCEQ’s adoption of the standard permit conditions for pollution control projects was consistent with the Clean Air Act. EFCH has also formally asked the EPA to stay, reconsider or clarify its disapproval. If the EPA declines to stay or reconsider its disapproval, EFCH asked the EPA to clarify whether it intends that entities, including EFCH, who obtained such permits for pollution control projects should stop operating the pollution control equipment permitted under the standard permit conditions. EFCH cannot predict the outcome of the litigation or the EPA’s response to EFCH’s request.

In November 2010, the EPA disapproved a different portion of the SIP under which the TCEQ had been phasing out a long-standing exemption for certain emissions that unavoidably occur during startup, shutdown and maintenance activities and replacing that exemption with a more limited affirmative defense that will itself be phased out and replaced by TCEQ-issued generation facility-specific permit conditions. EFCH, like many other electricity generation facility operators in Texas, have asserted applicability of the exemption or affirmative defense, and the TCEQ has not objected to that assertion. EFCH has also applied for the generation facility-specific permit conditions. The TCEQ is currently reviewing these applications. EFCH has challenged the EPA’s disapproval by filing a lawsuit in the US Court of Appeals for the Fifth Circuit arguing that the TCEQ’s adoption of the affirmative defense and phase-out of that affirmative defense as permits are issued is consistent with the Clean Air Act. EFCH cannot predict the outcome of this litigation.

In January 2011, the EPA retroactively disapproved a portion of the SIP pursuant to which the TCEQ issued permits for certain formerly non-permitted “grandfathered” facilities approximately 10 years ago. EFCH holds such permits. The EPA took this action despite acknowledging that emissions covered by these standard permits do not threaten attainment or maintenance of the NAAQS under the Clean Air Act. EFCH intends to challenge the EPA’s disapproval by filing a lawsuit in the US Court of Appeals for the Fifth Circuit arguing that the TCEQ’s adoption of the standard permit was consistent with the Clean Air Act. If the EPA’s action stands, and if it causes EFCH to undertake additional permitting activity and install additional emissions control equipment at EFCH’s affected generation facilities, EFCH could incur material capital expenditures.

EFCH believes that it holds all required emissions permits for facilities in operation. If the TCEQ adopts implementation plans that require EFCH to install additional emissions controls, or if the EPA adopts more stringent requirements through any of the number of potential rulemaking activities in which it is or may be engaged, EFCH could incur material capital expenditures, higher operating costs and potential production curtailments, resulting in material adverse effects on its financial condition, liquidity and results of operations.

Water

The TCEQ and the EPA have jurisdiction over water discharges (including storm water) from facilities in Texas. EFCH believes its facilities are presently in material compliance with applicable state and federal requirements relating to discharge of pollutants into water. EFCH believes it holds all required waste water discharge permits from the TCEQ for facilities in operation and have applied for or obtained necessary permits for facilities under construction. EFCH also believes it can satisfy the requirements necessary to obtain any required permits or renewals.

EFCH recently obtained a renewed and amended permit for discharge of waste water from its Oak Grove generation facility. Opponents to that permit renewal have initiated a challenge in Travis County, Texas District Court. EFCH and the State of Texas are defending the issuance of the permit. EFCH cannot predict the outcome of the litigation. If the permit is ultimately rejected by the courts, and EFCH is required to undertake additional permitting activity and install additional temperature-control equipment, EFCH could incur material capital expenditures, which could result in material adverse effects on its results of operations, liquidity and financial condition. (See Note 9 to Financial Statements.)

 

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Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQ and the EPA. EFCH believes it possesses all necessary permits for these activities from the TCEQ for its present operations. Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities were published by the EPA in 2004. As prescribed in the regulations, EFCH began implementing a monitoring program to determine the future actions that might need to be taken to comply with these regulations. In January 2007, a federal court ruled against the EPA in a lawsuit brought by environmental groups challenging aspects of these regulations, and in July 2007, the EPA announced that it was suspending the regulations pending further rulemaking. The US Supreme Court issued a decision in April 2009 reversing the federal court’s decision, in part, and finding that the EPA permissibly used cost-benefit analysis in the Section 316(b) regulations. In the absence of regulations, the EPA has instructed the states implementing the Section 316(b) program to use best professional judgment in reviewing applications and issuing permits under Section 316(b). The EPA has entered into a settlement agreement that requires it to propose new rules by March 2011 and to finalize those rules by July 2012. EFCH cannot predict the impact on its operations of the suspended regulations or of new regulations that replace them.

Radioactive Waste

EFCH currently ships low-level waste material to a disposal facility outside of Texas. Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the State of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. The State of Texas has agreed to a compact for a disposal facility that would be located in Texas. That compact was ratified by Congress and signed by the President in 1998. In 2003, the State of Texas enacted legislation allowing a private entity to be licensed to accept low-level radioactive waste for disposal, and in 2004 the State received a license application from such an entity for review. In January 2009, the TCEQ approved this permit. EFCH expects to continue to ship low-level waste material off-site for as long as an alternative disposal site is available. Should existing off-site disposal become unavailable, the low-level waste material will be stored on-site. (See discussion under “Luminant — Nuclear Generation Operations” above.) A rate case is currently before the TCEQ to determine the rates to be charged by the owner of waste disposal facilities to customers (potentially including TCEH) for disposal of low-level radioactive waste in Texas.

EFCH believes its on-site used nuclear fuel storage capability is sufficient for a minimum of three years. The nuclear industry is continuing to review ways to enhance security of used-fuel storage with the NRC to fully utilize physical storage capacity. Future on-site used nuclear fuel storage capability will require the use of the industry technique of dry cask storage.

Solid Waste, Including Fly Ash Associated with Lignite/Coal-Fueled Generation

Treatment, storage and disposal of solid waste and hazardous waste are regulated at the state level under the Texas Solid Waste Disposal Act and at the federal level under the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act. The EPA has issued regulations under the Resource Conservation and Recovery Act of 1976 and the Toxic Substances Control Act, and the TCEQ has issued regulations under the Texas Solid Waste Disposal Act applicable to EFCH’s facilities. EFCH believes it is in material compliance with all applicable solid waste rules and regulations. In addition, EFCH has registered solid waste disposal sites and has obtained or applied for permits required by such regulations.

In December 2008, an ash impoundment facility at a Tennessee Valley Authority (TVA) site ruptured releasing a significant quantity of coal ash slurry. No impoundment failures of this magnitude have ever occurred at any of EFCH’s impoundments, which are significantly smaller than the TVA’s and are inspected on a regular basis. EFCH routinely samples groundwater monitoring wells to ensure compliance with all applicable regulations. As a result of the TVA ash impoundment failure, in May 2010, the EPA released a proposed rule that considers regulating coal combustion residuals as either a hazardous waste or a non-hazardous waste. EFCH is unable to predict the requirements of a final rule; however, the potential cost of compliance could be material.

 

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The EPA issued a notice in December 2009 that it had identified several industries, including the electric power industry, which should be subject to financial responsibility requirements under the Comprehensive Environmental Response, Compensation and Liability Act consistent with the risk associated with their production, transportation, treatment, storage or disposal of hazardous substances. The EPA indicated in its notice that it would develop regulations that define the scope of those financial responsibility requirements. EFCH does not know, at this time, the scope of these requirements, nor is EFCH able to estimate the potential cost (which could be material) of complying with any such new requirements.

Environmental Capital Expenditures

Capital expenditures for EFCH’s environmental projects totaled $106 million in 2010 and are expected to total approximately $75 million in 2011, consisting primarily of environmental projects at existing lignite/coal-fueled generation plants. The 2010 amount is exclusive of emissions control equipment investment as part of the three-unit generation development program, which totaled approximately $500 million over the construction period. See discussion above under “Luminant — Lignite/Coal-Fueled Generation Operations” regarding planned investments in emissions control systems.

 

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Item 1A. RISK FACTORS

Some important factors, in addition to others specifically addressed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” that could have a material negative impact on EFCH’s operations, financial results and financial condition, or could cause EFCH’s actual results or outcomes to differ materially from any projected outcome contained in any forward-looking statement in this report, include:

Risks Related to Substantial Indebtedness and Debt Agreements

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

EFCH is highly leveraged. As of December 31, 2010, EFCH’s consolidated principal amount of debt (short-term borrowings and long-term debt, including amounts due currently) totaled $31.5 billion (see Note 8 to Financial Statements). EFCH’s substantial leverage could have important consequences, including:

 

   

making it more difficult for EFCH to make payments on its debt;

 

   

requiring a substantial portion of cash flow to be dedicated to the payment of principal and interest on debt, thereby reducing EFCH’s ability to use its cash flow to fund operations, capital expenditures and future business opportunities and execute its strategy;

 

   

increasing vulnerability to adverse economic, industry or competitive developments;

 

   

exposing EFCH to the risk of increased interest rates because, as of December 31, 2010, taking into consideration interest swap transactions, 15% of EFCH’s long-term borrowings were at variable rates of interest;

 

   

limiting ability to make strategic acquisitions or causing EFCH to make non-strategic divestitures;

 

   

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

 

   

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

EFCH may not be able to repay or refinance the TCEH Revolving Credit Facility, which matures in October 2013, other debt incurred under the TCEH Senior Secured Facilities, which mature in October 2014, or its other debt as or before it becomes due, particularly if forward natural gas prices do not significantly increase.

EFCH may not be able to repay or refinance its debt obligations as or before they become due, or may be able to refinance such amounts only on terms that will increase its cost of borrowing or on terms that may be more onerous. EFCH’s ability to successfully implement any future refinancing of its debt will depend, among other things, on EFCH’s financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond EFCH’s control, including, without limitation, wholesale electricity prices in ERCOT (which are primarily driven by the price of natural gas and ERCOT market heat rates) and general conditions in the credit markets. Refinancing may be difficult because of the slow economic recovery, the possibility of rising interest rates and the impending surge of large debt maturities of other borrowers. Due to the weakness of EFCH’s credit, it may be more heavily exposed to these refinancing risks than other borrowers.

 

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A substantial amount of EFCH’s debt is comprised of debt incurred under the TCEH Senior Secured Facilities, the majority of which matures in October 2014. The TCEH Revolving Credit Facility, which has a facility limit of $2.7 billion and availability of $1.4 billion (including $94 million of commitments from Lehman that are only available from the fronting banks and the swingline lenders) as of December 31, 2010, matures in October 2013. The TCEH Revolving Credit Facility is used for letters of credit and borrowings for general corporate purposes. EFCH may not be able to refinance the TCEH Senior Secured Facilities, including the TCEH Revolving Credit Facility, or its other debt because of EFCH’s high levels of existing debt. For example, EFCH may not be able to refinance the TCEH Revolving Credit Facility unless prior to or concurrently with such refinancing EFCH refinances or otherwise extends the maturity of a substantial portion of its debt due in 2014. Consequently, even though most of EFCH’s debt matures in October 2014, the earlier maturity of the TCEH Revolving Credit Facility may effectively cause EFCH to address the 2014 debt maturities at an earlier time than it might otherwise choose. Similarly, lenders of debt due in 2014 may be unwilling to refinance or otherwise extend the maturity of their lendings unless prior to or concurrently with such refinancing EFCH refinances or otherwise extends the maturity of a substantial portion of its debt due in the period 2015 to 2017. As of December 31, 2010, $5.4 billion principal amount of EFCH’s debt matures in the period 2015 to 2017. This “pull-forward” effect, which may cause EFCH to refinance several maturities at once as the first becomes due, could increase EFCH’s near-term refinancing needs.

Wholesale electricity prices in the ERCOT market largely correlate with the price of natural gas. Accordingly, the contribution to earnings and the value of EFCH’s baseload generation assets are dependent in significant part upon the price of natural gas. Forward natural gas prices have generally trended downward since mid-2008. In recent years natural gas supply has outpaced demand as a result of increased drilling of shale gas deposits combined with lingering demand weakness associated with the economic recession and many industry experts expect this supply/demand imbalance to continue for a number of years, thereby depressing natural gas prices for a long-term period. These market conditions are challenging to the long-term profitability of EFCH’s generation assets. Specifically, low natural gas prices and their correlated effect in ERCOT on wholesale electricity prices could have a material adverse impact on the overall profitability of EFCH’s generation assets for periods in which it does not have significant hedge positions. As of December 31, 2010, EFCH has hedged only approximately 51% and 19% of its wholesale natural gas price exposure related to expected generation output for 2013 and 2014, respectively, and does not have any significant amounts of hedges in place for periods after 2014. A continuation of current forward natural gas prices or a further decline of forward natural gas prices could limit EFCH’s ability to hedge its wholesale electricity revenues at sufficient price levels to support its interest payments and debt maturities, result in further declines in the values of its baseload generation assets and adversely impact EFCH’s ability to refinance the TCEH Revolving Credit Facility due in October 2013 or its substantial debt due in October 2014.

In addition, EFCH’s liabilities exceed its assets as shown on its balance sheet prepared in accordance with US GAAP as of December 31, 2010. EFCH’s assets include $6.2 billion of goodwill as of December 31, 2010. In the third quarter 2010, EFCH recorded a $4.1 billion noncash goodwill impairment charge reflecting the estimated effect of lower wholesale electricity prices on the enterprise value of TCEH, driven by the sustained decline in forward natural gas prices, as indicated by EFCH’s cash flow projections and declines in market values of securities of comparable companies. The value of EFCH’s goodwill will continue to depend on, among other things, wholesale electricity prices in the ERCOT market. Recent valuation analyses of TCEH’s business indicate that the principal amount of its outstanding debt currently exceeds its enterprise value. EFCH may have difficulty successfully implementing any refinancing of its debt due to its financial position as reflected in its balance sheet and the valuation analyses.

EFCH may pursue transactions and initiatives that are unsuccessful or do not produce the desired outcome.

Future transactions and initiatives that EFCH may pursue may have significant effects on its business, capital structure, liquidity and/or results of operations. For example, in addition to the exchanges and repurchases of its debt that are described in Note 8 to Financial Statements, EFCH has and may continue to pursue, from time to time, transactions and initiatives of various types, including, without limitation, debt exchange transactions, debt repurchases, equity or debt issuances, debt financing transactions (including extensions of maturity dates of EFCH’s debt), asset sales, joint ventures, recapitalizations, business combinations and other strategic transactions. There can be no guarantee that any of such transactions or initiatives would be successful or produce the desired outcome, which could ultimately affect EFCH in a material and adverse manner. Moreover, the effects of any of these transactions or initiatives could be material and adverse to holders of EFCH’s debt and could be disproportionate, and directionally different, with respect to one class or type of debt than with respect to others.

 

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

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

Increases in interest rates may negatively impact EFCH’s results of operations, liquidity and financial condition.

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

As of December 31, 2010, EFCH had $4.514 billion aggregate principal amount of variable rate long-term debt (excluding $1.135 billion of long-term borrowings associated with the TCEH Letter of Credit Facility that are invested at a variable rate), taking into account interest rate swaps that fix the interest rate on $15.8 billion in notional amount of variable rate debt. As a result, as of December 31, 2010, a 100 basis point increase in interest rates would increase EFCH’s annual interest expense by approximately $45 million. See discussion of interest rate swap transactions in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Activities and Events.”

EFCH’s interest expense and related charges for the year ended December 31, 2010 totaled $3.067 billion, including $207 million of unrealized mark-to-market net losses on interest rate swaps.

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

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

 

   

incur additional debt 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 on assets to secure debt;

 

   

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

 

   

enter into transactions with affiliates;

 

   

designate subsidiaries as unrestricted subsidiaries, and

 

   

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

There are a number of important limitations and exceptions to these covenants and other restrictions. See Note 8 to Financial Statements for a description of these covenants and other restrictions.

Under the TCEH Senior Secured Facilities, TCEH is required to maintain a consolidated secured debt to consolidated EBITDA ratio below specified levels. TCEH’s ability to maintain the consolidated secured debt to consolidated EBITDA ratio below such levels can be affected by events beyond its control, including, without limitation, wholesale electricity prices (which are primarily derived by the price of natural gas and ERCOT market heat rates), and there can be no assurance that TCEH will comply with this ratio.

 

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

In addition, EFH Corp. and Oncor have implemented a number of “ring-fencing” measures to enhance the credit quality of Oncor Holdings and its subsidiaries, including Oncor. Those measures include Oncor not guaranteeing or pledging any of its assets to secure the debt of Texas Holdings and its other subsidiaries. Accordingly, Oncor’s assets will not be available to repay any of EFCH’s debt.

EFCH may not be able to generate sufficient cash to service all of its debt and may be forced to take other actions to satisfy its obligations under its debt agreements, which may not be successful.

EFCH’s ability to make scheduled payments on its debt obligations depends on EFCH’s financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond EFCH’s control, including, without limitation, wholesale electricity prices (which are primarily driven by the price of natural gas and ERCOT market heat rates). EFCH may not be able to maintain a level of cash flows sufficient to permit it to pay the principal, premium, if any, and interest on its debt.

If cash flows and capital resources are insufficient to fund its debt service obligations, EFCH 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 debt. These alternative measures may not be successful, may not be completed on economically attractive terms or may not be adequate for EFCH to meet its debt service obligations when due. Additionally, EFCH’s debt agreements limit the use of the proceeds from many dispositions of assets or operations. As a result, EFCH may not be allowed, under these documents, to use proceeds from these dispositions to satisfy its debt service obligations.

 

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Risks Related to Structure

EFCH and TCEH are holding companies and their obligations are structurally subordinated to existing and future liabilities and preferred stock of their subsidiaries.

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

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

EFH Corp. relies significantly on loans from TCEH to meet its obligations, and such reliance may intensify if EFH Corp. does not receive distributions from Oncor.

EFH Corp. is a holding company and substantially all of its reported consolidated assets are held by its subsidiaries. As of December 31, 2010, TCEH and its subsidiaries held approximately 80% of EFH Corp.’s reported consolidated assets and for the year ended December 31, 2010, TCEH and its subsidiaries represented all of EFH Corp.’s reported consolidated revenues. Accordingly, EFH Corp. depends upon TCEH for a significant amount of its cash flows and relies on such cash flows in order to pay its obligations, which are significant. The terms of the indentures governing the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities permit TCEH to make loans and/or dividends (to the extent permitted by applicable state law) to cover certain of EFH Corp.’s obligations, including principal and interest payments, working capital requirements and SG&A and corporate overhead costs and expenses. As of December 31, 2010, TCEH has notes receivable from EFH Corp. totaling $1.9 billion (see Note 19 to Financial Statements), and TCEH may make additional loans to EFH Corp. in the future.

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

As part of the ring-fencing measures, a majority of the members of the board of directors of Oncor are required to be, and are, independent from EFH Corp. Any new independent directors of Oncor are required to be appointed by the nominating committee of Oncor Holdings. The organizational documents of Oncor give these independent directors, acting by majority vote, and, during certain periods, any director designated by Texas Transmission Investment LLC (which owns approximately 19.75% of Oncor), 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 may result in EFH Corp. relying on loans and distributions from TCEH to meet a substantial amount of its obligations.

In addition, Oncor’s organizational documents limit Oncor’s distributions to its owners, including EFH Corp., through December 31, 2012 to an amount not to exceed Oncor’s net income (determined in accordance with US GAAP, subject to certain defined adjustments, including goodwill impairments) and prohibit Oncor from making any distribution to EFH Corp. so long as and to the extent that such distribution would cause Oncor’s regulatory capital structure to exceed the debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. In January 2011, Oncor filed a rate review that, among other things, requested a revised regulatory capital structure of 55% debt to 45% equity.

Risks Related to Businesses

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

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

 

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EFCH’s businesses are subject to changes in state and federal laws (including PURA, the Federal Power Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act and the Energy Policy Act of 2005), changing governmental policy and regulatory actions (including those of the PUCT, the NERC, the TRE, the RRC, the TCEQ, the FERC, the EPA, the NRC and the CFTC) and the rules, guidelines and protocols of ERCOT with respect to matters including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, 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 any wholesale power sales outside the ERCOT market, is subject to market behavior and other competition-related rules and regulations under the Federal Power Act that are administered by the FERC. Changes in, revisions to, or reinterpretations of existing laws and regulations (for example, with respect to prices at which TCEH may sell electricity or the cost of emitting greenhouse gases) may have a material and adverse effect on EFCH’s businesses.

The Texas Legislature meets every two years (the current legislative session began in January 2011), and from time to time bills are introduced and considered that could materially affect EFCH’s businesses. The State of Texas currently faces a substantial budget deficit, and the Texas Legislature is expected to enact spending cuts to address this shortfall. EFCH cannot predict whether spending cuts or other actions taken with respect to the budget deficit will affect the PUCT or other agencies that relate to EFCH’s business or whether any such spending cuts or other actions taken with respect to the budget deficit will have a material impact on EFCH’s business. There can be no assurance that future action of the Texas Legislature will not result in legislation that could have a material adverse effect on EFCH and its financial prospects.

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

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

 

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

EFCH is involved in the ordinary course of business in a number of lawsuits involving employment, commercial and environmental issues, and other claims for injuries and damages, among other matters. EFCH evaluates litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these assessments and estimates, EFCH establishes reserves and discloses the relevant litigation claims or legal proceedings, as appropriate. These assessments and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current assessments and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on EFCH’s results of operations. In addition, judges and juries in the State of Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage and business tort cases. EFCH uses appropriate means to contest litigation threatened or filed against it, but the litigation environment in the State of Texas poses a significant business risk.

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

EFCH is also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and EFCH is exposed to the risk that it may become the subject of additional regulatory investigations or administrative proceedings. See Item 3, “Legal Proceedings — Regulatory Investigations and Reviews.” While EFCH cannot predict the outcome of any regulatory investigation or administrative proceeding, any such regulatory investigation or administrative proceeding could result in EFCH incurring material penalties and/or other costs and have a material adverse effect on it results of operations and liquidity.

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

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

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

 

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

 

   

volatility in natural gas prices;

 

   

volatility in market heat rates;

 

   

volatility in coal and rail transportation prices;

 

   

severe or unexpected weather conditions;

 

   

seasonality;

 

   

changes in electricity and fuel usage;

 

   

illiquidity in the wholesale power or other markets;

 

   

transmission or transportation constraints, inoperability or inefficiencies;

 

   

availability of competitively-priced alternative energy sources;

 

   

changes in market structure;

 

   

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

 

   

changes in the manner in which EFCH operates its facilities, including curtailed operation due to market pricing, environmental, safety or other factors;

 

   

changes in generation efficiency;

 

   

outages or otherwise reduced output from EFCH’s generation facilities or those of its competitors;

 

   

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

 

   

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

 

   

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

 

   

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

All of EFCH’s generation facilities are located in the ERCOT market, a market with limited interconnections to other markets. Wholesale electricity prices in the ERCOT market generally correlate with the price of natural gas because marginal electricity demand is generally supplied by natural gas-fueled generation facilities. Accordingly, EFCH’s earnings and the value of its baseload generation assets, which provided a substantial portion of its supply volumes in 2010, are dependent in significant part upon the price of natural gas. Forward natural gas prices have generally trended downward since mid-2008. In recent years natural gas supply has outpaced demand as a result of increased drilling of shale gas deposits combined with lingering demand weakness associated with the economic recession, and many industry experts expect this supply/demand imbalance to continue for a number of years, thereby depressing natural gas prices for a long-term period. While EFCH’s hedging activities, in particular its long-term hedging program, are designed to mitigate the effect on earnings of low wholesale electricity prices, due to low natural gas prices, these market conditions are challenging to the long-term profitability of EFCH’s generation assets. Specifically, the low natural gas prices and the correlated effect in ERCOT on wholesale power prices could have a material adverse impact on the overall profitability of EFCH’s generation assets for periods in which EFCH does not have significant hedge positions. While EFCH has significantly hedged its natural gas price exposure for 2011 and 2012 (approximately 99% and 87%, respectively), as of December 31, 2010, EFCH has hedged only approximately 51% and 19% of its wholesale natural gas price exposure related to expected generation output for 2013 and 2014, respectively, and does not have any significant amount of hedges in place for periods after 2014. A continuation of current forward natural gas prices or a further decline of forward natural gas prices could limit EFCH’s ability to hedge its wholesale electricity revenues at sufficient price levels to support its interest payments and debt maturities, result in further declines in the value of EFCH’s baseload generation assets and could adversely impact EFCH’s ability to refinance the TCEH Revolving Credit Facility due in October 2013 or EFCH’s substantial debt due in October 2014.

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, EFCH’s earnings and the value of EFCH’s baseload (lignite/coal-fueled and nuclear) generation assets, which provided a substantial portion of its supply volumes in 2010, are also dependent in significant part upon market heat rates. As a result, EFCH’s baseload generation assets could significantly decrease in profitability and value if market heat rates continue at current levels or decline.

 

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

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

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

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

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

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

In July 2010, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Financial Reform Act) was enacted. While the legislation is broad and detailed, substantial portions of the legislation are currently under rulemakings by federal governmental agencies to implement the standards set out in the legislation and adopt new standards.

Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives market. The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that EFCH uses to hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However, entities are exempt from these clearing requirements if they (i) are not “Swap Dealers” or “Major Swap Participants” as will be defined in the rulemakings and (ii) use the swaps to hedge or mitigate commercial risk. The proposed definition of Swap Dealer is broad and will, as drafted, include many end users. EFCH is evaluating whether or not the type of asset-backed OTC derivatives that it uses to hedge commodity and interest rate risk is exempt from the clearing requirements. Existing swaps are grandfathered from the clearing requirements. The legislation mandates significant reporting and compliance requirements for any entity that is determined to be a Swap Dealer or Major Swap Participant.

 

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

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

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

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

 

   

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

 

   

inadequacy or lapses in maintenance protocols;

 

   

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

 

   

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

 

   

the costs of procuring nuclear fuel;

 

   

the costs of securing the plant against possible terrorist attacks;

 

   

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

 

   

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

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

 

   

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

 

   

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

 

   

Nuclear Accident Risk — Although the safety record of Comanche Peak and other nuclear generation facilities generally has been very good, accidents and other unforeseen problems have occurred both in the US and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impact, and property damage. Any accident, or perceived accident, could result in significant liabilities and damage EFCH’s reputation. Any such resulting liability from a nuclear accident could exceed EFCH’s resources, including insurance coverage.

 

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The operation and maintenance of electricity generation facilities involves significant risks that could adversely affect EFCH’s results of operations, liquidity 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 reliability, the occurrence of any of which could result in lost revenues and/or increased expenses. A significant number of EFCH’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 and availability. 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 and the prospect of continuing low wholesale electricity prices that may not justify sustained or year-round operation of all EFCH’s generating facilities, (b) any unexpected failure to generate electricity, including failure caused by equipment breakdown or forced outage and (c) damage to facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events. Further, EFCH’s ability to successfully and timely complete capital improvements to existing facilities or other capital projects is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, EFCH could be subject to additional costs or losses and writedowns on its investment in the project or improvement.

Insurance, warranties or performance guarantees may not cover all or any of the lost revenues or increased expenses that could result from the risks discussed above, 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 EFCH’s control.

Maintenance, expansion and refurbishment of power generation facilities involve significant risks that could result in unplanned power outages or reduced output and could have a material adverse effect on EFCH’s results of operations, liquidity and financial condition.

Many of EFCH’s facilities are old and require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could materially adversely affect EFCH’s results of operations, liquidity and financial condition.

EFCH cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events (such as natural disasters or terrorist attacks). The unexpected requirement of large capital expenditures could materially adversely affect EFCH’s results of operations, liquidity and financial condition.

If EFCH makes any major modifications to its power generation facilities, it may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the Clean Air Act. Any such modifications would likely result in substantial additional capital expenditures.

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

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

 

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

In conjunction with the building of three new generation units, EFCH has committed to reduce emissions of mercury, NOX and SO2 through the installation of emissions control equipment at both the new and existing lignite-fueled generation units. EFCH 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 EFCH in its pursuit of technology development opportunities that, among other things, are designed to reduce EFCH’s impact on the environment. Any adoption of Sustainable Energy Advisory Board recommendations may cause EFCH to incur significant costs in addition to the costs referenced above.

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

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

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

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

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

 

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The EPA also announced in late 2010 its intent to promulgate, in 2011, GHG emission limits known as New Source Performance Standards that would apply to new and modified sources, as well as GHG emission guidelines that states might apply to existing sources of GHGs. The EPA has indicated that such new standards and guidelines would be applicable to electricity generation facilities. EFCH cannot predict what limits or guidelines the EPA might adopt. If the limits or guidelines become applicable to EFCH’s generation facilities and require EFCH to install new control equipment or substantially alter its operations, it could have a material adverse effect on EFCH’s results of operations, liquidity and financial condition.

EFCH produces GHG emissions from the combustion of fossil fuels at its generation facilities. For 2010, EFCH estimates that its generation facilities produced 64 million short tons of CO2 based on continuously monitored data reported to and subject to approval by the EPA. Because a substantial portion of EFCH’s generation portfolio consists of lignite/coal-fueled generation facilities, its results of operations, liquidity and financial condition could be materially adversely affected by the enactment of any legislation or regulation that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes upon those that produce GHG emissions. For example, to the extent a cap-and-trade program is adopted, EFCH may be required to incur material costs to reduce its GHG emissions or to procure emission allowances or credits to comply with such a program. The EPA regulation of GHGs under the Clean Air Act, or judicially imposed limits on GHG emissions, may require EFCH to make material expenditures to reduce its GHG emissions. If a significant number of EFCH’s customers or others refuse to do business with it because of its GHG emissions, it could have a material adverse effect on EFCH’s results of operations, liquidity or financial condition.

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

EFCH’s results of operations may be affected by weather conditions and may fluctuate substantially on a seasonal basis as the weather changes. In addition, EFCH could be subject to the effects of extreme weather. Extreme weather conditions could stress EFCH’s generation facilities resulting in outages, increased maintenance and capital expenditures. Extreme weather events, including sustained cold temperatures, hurricanes or storms or other natural disasters, could be destructive and result in casualty losses that are not ultimately offset by insurance proceeds or in increased capital expenditures or costs, including supply chain costs.

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

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

The implementation of performance improvement initiatives identified by management may not produce the desired reduction in costs and if unsuccessful, may instead result in significant additional costs as well as significant disruptions in EFCH’s operations due to employee displacement and the rapid pace of changes to organizational structure and operating practices and processes. Such additional costs or operational disruptions could have an adverse effect on EFCH’s businesses and financial prospects.

Attacks on EFCH’s infrastructure that breach cyber/data security measures could expose EFCH to significant liabilities and reputation damage and disrupt business operations, which could have a material adverse effect on EFCH’s financial condition, results of operations and liquidity.

A breach of cyber/data security measures that impairs EFCH’s information technology infrastructure could disrupt normal business operations and affect its ability to control its generation assets, access retail customer information and limit communication with third parties. Any loss of confidential or proprietary data through a breach could adversely affect EFCH’s reputation, expose the company to legal claims, impair EFCH’s ability to execute on business strategies and/or materially and adversely affect EFCH’s financial condition, results of operations and liquidity.

 

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

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

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

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

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, and it may have to forgo sales or buy more expensive wholesale electricity than is available in the capacity-constrained area. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where TXU Energy has a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower profits. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to TXU Energy’s customers could negatively impact the satisfaction of its customers with its service.

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

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

 

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

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

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

Research and development activities are ongoing to improve existing and alternative technologies to produce electricity, including gas turbines, fuel cells, microturbines, photovoltaic (solar) cells and concentrated solar thermal devices. It is possible that advances in these or other technologies will reduce the costs of electricity production from these technologies to a level that will enable these technologies to compete effectively with EFCH’s traditional generation facilities. Consequently, where EFCH has facilities, the profitability and market value of its generation assets could be significantly reduced. Changes in technology could also alter the channels through which retail customers buy electricity. To the extent self-generation facilities become a more cost-effective option for certain customers, EFCH’s revenues could be materially reduced.

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

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

A significant amount of investment in wind generation in the ERCOT market over the past few years has increased overall wind power generation capacity. Generally, the increased capacity has led to lower wholesale electricity prices (driven by lower market heat rates) in the regions at or near wind power development. As a result, the profitability of EFCH’s generation facilities and power purchase contracts, including certain wind generation power purchase contracts, has been impacted and could be further impacted by the effects of the wind power development, and the value could significantly decrease if wind power generation has a material sustained effect on market heat rates.

EFCH’s revenues and results of operations may be adversely impacted by the ERCOT market’s recent transition from a zonal to a nodal wholesale market structure.

Substantially all of EFCH’s competitive businesses are located in the ERCOT market, which has recently transitioned from a zonal market structure with four congestion management zones to a nodal market structure that directly manages congestion on a localized basis. In a nodal market, the prices received and paid for power are based on pricing determined at specific interconnection points on the transmission grid (i.e., Locational Marginal Pricing), which could result in lower revenues or higher costs for EFCH’s competitive businesses. This market structure change could have a significant impact on the profitability and value of EFCH’s competitive businesses depending on how the Locational Marginal Pricing develops, particularly if such development ultimately results in lower revenue due to lower wholesale electricity prices, increased costs to service end-user electricity demand or increased collateral posting requirements with ERCOT. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Activities and Events — Wholesale Market Design — Nodal Market.”

 

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

ERCOT is the independent system operator that is responsible for maintaining reliable operation of the bulk electric power supply system in the ERCOT market. Its responsibilities include the clearing and settlement of electricity volumes and related ancillary services among the various participants in the deregulated Texas market. Settlement information for most operating activity 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, EFCH is subject to settlement adjustments from ERCOT related to prior periods, which may result in charges or credits impacting its future reported results of operations.

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

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

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

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

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

Market volatility may have impacts on EFCH’s businesses and financial condition that EFCH currently cannot predict.

Because EFCH’s operations are capital intensive, it expects to rely over the long-term upon access to financial markets (particularly the attainment of liquidity facilities) as a significant source of liquidity for capital requirements not satisfied by cash-on-hand, operating cash flows or its revolving credit facilities. The capital and credit markets experienced extreme volatility and disruption in 2008 and 2009. EFCH’s ability to access the capital or credit markets may be severely restricted at a time when EFCH would like, or need, to access those markets, which could have an impact on its flexibility to react to changing economic and business conditions. In addition, the cost of debt financing may be materially impacted by these market conditions. Accordingly, there can be no assurance that the capital and credit markets will continue to be a reliable or acceptable source of short-term or long-term financing for EFCH. Additionally, disruptions in the capital and credit markets could have a broader impact on the economy in general in ways that could lead to reduced electricity usage, which could have a negative impact on EFCH’s revenues, or have an impact on EFCH’s customers, counterparties and/or lenders, causing them to fail to meet their obligations to EFCH.

 

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

EFCH’s businesses are capital intensive. EFCH relies on access to financial markets and liquidity facilities as a significant source of liquidity for capital requirements not satisfied by cash-on-hand or operating cash flows. The inability to raise capital on favorable terms or access liquidity facilities, particularly during times of uncertainty similar to those experienced in the financial markets in 2008 and 2009, could impact EFCH’s ability to sustain and grow its businesses and would likely increase capital costs. EFCH’s access to the financial markets and liquidity facilities could be adversely impacted by various factors, such as:

 

   

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

 

   

economic weakness in the ERCOT or general US market;

 

   

changes in interest rates;

 

   

a deterioration of EFCH’s credit or the credit of its subsidiaries or a reduction in EFCH or its applicable subsidiaries’ credit ratings;

 

   

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

 

   

volatility in commodity prices that increases margin or credit requirements;

 

   

a material breakdown in EFCH’s risk management procedures, and

 

   

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

Although EFCH expects to actively manage the liquidity exposure of existing and future hedging arrangements, given the size of the long-term hedging program, any significant increase in the price of natural gas could result in EFCH being required to provide cash or letter of credit collateral in substantial amounts. While these potential posting obligations are primarily supported by the liquidity facilities, for certain transactions there is a potential for the timing of postings on the commodity contract obligations to vary from the timing of borrowings from the TCEH Commodity Collateral Posting Facility. Any perceived reduction in EFCH’s credit quality could result in clearing agents or other counterparties requesting additional collateral. EFCH has credit concentration risk related to the limited number of lenders that provide liquidity to support its hedging program. A deterioration of the credit quality of such lenders could materially affect EFCH’s ability to continue such program on acceptable terms. An event of default by one or more of EFCH’s hedge counterparties could result in termination-related settlement payments that reduce available liquidity if EFCH owes amounts related to commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to EFCH. These events could have a material negative impact on EFCH’s results of operations, liquidity and financial condition.

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

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

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

 

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The costs of providing pension and OPEB and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on EFCH’s results of operations, liquidity and financial condition.

EFH Corp. provides pension benefits based on either a traditional defined benefit formula or a cash balance formula and also provides certain health care and life insurance benefits to eligible employees of EFCH and their eligible dependents upon the retirement of such employees. EFCH’s costs of providing such benefits and related funding requirements are dependent upon numerous factors, assumptions and estimates and are subject to changes in these factors, assumptions and estimates, including the market value of the assets funding EFH Corp.’s pension and OPEB plans. Fluctuations in financial market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.

The values of the investments that fund EFH Corp.’s pension and OPEB plans are subject to changes in financial market conditions, such as the substantial dislocation that began in 2008. Significant decreases in the values of these investments could increase the expenses of the pension plan and the costs of the OPEB plans and related funding requirements in the future. EFCH’s costs of providing such benefits and related funding requirements are also subject to changing employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in financial market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods. See Note 16 to Financial Statements for further discussion of EFH Corp.’s pension and OPEB plans.

As was the case in the third quarter 2010 (as discussed in Note 2 to Financial Statements), goodwill and/or other intangible assets not subject to amortization that EFCH has recorded in connection with the Merger are subject to at least annual impairment evaluations, and as a result, EFCH could be required to write off some or all of this goodwill and other intangible assets, which may cause adverse impacts on its results of operations and financial condition.

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

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

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

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

The Sponsor Group indirectly owns approximately 60% of EFH Corp.’s capital stock on a fully-diluted basis through its 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 EFCH’s operations, plans, strategies, finances and structure, including whether to enter into any corporate transaction, and will have the ability to prevent any transaction that requires the approval of EFCH’s shareholder.

 

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

 

Item 1B. UNRESOLVED STAFF COMMENTS

None.

 

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Item 3. LEGAL PROCEEDINGS

Litigation Related to Generation Facilities

In November 2010, an administrative appeal challenging the decision of the TCEQ to renew and amend Oak Grove Management Company LLC’s (Oak Grove) (a wholly-owned subsidiary of TCEH) Texas Pollutant Discharge Elimination System (TPDES) permit related to water discharges was filed by Robertson County: Our Land, Our Lives and Roy Henrichson in the Travis County, Texas District Court. Plaintiffs seek a reversal of the TCEQ’s order and a remand back to the TCEQ for further proceedings. In addition to this administrative appeal, in November 2010, two other petitions were filed in Travis County, Texas District Court by Sustainable Energy and Economic Development Coalition and Paul and Lisa Rolke, respectively, who were non-parties to the administrative hearing before the State Office of Administrative Hearings, challenging the TCEQ’s decision to renew and amend Oak Grove’s TPDES permit and asking the District Court to remand the matter to the TCEQ for further proceedings. Although EFCH cannot predict the outcome of these proceedings, EFCH believes that the renewal and amendment of the Oak Grove TPDES permit are protective of the environment and that the application for and the processing of Oak Grove’s TPDES permit renewal and amendment by the TCEQ were in accordance with applicable law. There can be no assurance that the outcome of these matters would not result in an adverse impact on EFCH’s financial condition, results of operations or liquidity.

In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (Texarkana Division) against EFH Corp. and Luminant Generation Company LLC (a wholly-owned subsidiary of TCEH) for alleged violations of the Clean Air Act at Luminant’s Martin Lake generation facility. While EFCH is unable to estimate any possible loss or predict the outcome of the litigation, EFCH believes that the Sierra Club’s claims are without merit, and intends to vigorously defend this litigation. In addition, in February 2010, the Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Big Brown generation facility. Subsequently, in December 2010, Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Monticello generation facility. EFCH cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.

Regulatory Reviews

In June 2008, the EPA issued a request for information to TCEH under the EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.

Other Proceedings

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

 

Item 4. (REMOVED AND RESERVED)

 

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PART II

 

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

Not applicable. All of EFCH’s common stock is owned by EFH Corp.

See Note 10 to Financial Statements for a description of the restrictions on EFCH’s ability to pay dividends.

 

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Item 6. SELECTED FINANCIAL DATA

EFCH AND SUBSIDIARIES

SELECTED FINANCIAL DATA

(millions of dollars, except ratios)

M900[H]

 

    Successor             Predecessor  
    Year Ended December 31,     Period from
October 11, 2007
through
            Period from
January 1, 2007
through
    Year Ended  
    2010     2009     2008     December 31, 2007             October 10, 2007     December 31, 2006  

Operating revenues

  $ 8,235      $ 7,911      $ 9,787      $ 1,671          $ 6,884      $ 9,396   

Net income (loss)

    (3,530     515        (9,039     (1,266         1,306        2,501   

Net (income) loss attributable to noncontrolling interests

    —          —          —          —              —          —     

Net income (loss) attributable to EFCH

    (3,530     515        (9,039     (1,266         1,306        2,501   

Ratio of earnings to fixed charges (a)

    —          1.36        —          —              5.88        10.84   

Capital expenditures, including nuclear fuel

  $ 902      $ 1,521      $ 2,074      $ 519          $ 1,585      $ 908   

See Notes to Financial Statements.

 

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EFCH AND SUBSIDIARIES

SELECTED FINANCIAL DATA (CONTINUED)

(millions of dollars, except ratios)

 

     Successor               Predecessor  
     As of December 31,               As of
December 31, 2006
 
     2010     2009     2008     2007              

Total assets

   $ 39,144      $ 43,245      $ 43,000      $ 49,152            $ 21,149   

Property, plant & equipment — net

   $ 20,155      $ 20,980      $ 20,902      $ 20,545            $ 10,344   

Goodwill and intangible assets

   $ 8,523      $ 12,845      $ 13,096      $ 22,197            $ 526   
 

Capitalization

                

Long-term debt, less amounts due currently

   $ 29,474      $ 32,121      $ 31,556      $ 30,762            $ 3,088   

EFCH shareholder’s equity

     (6,236     (4,266     (5,002     4,003              7,943   

Noncontrolling interests in subsidiaries

     87        48        —          —                —     
                                              

Total

   $ 23,325      $ 27,903      $ 26,554      $ 34,765            $ 11,031   
                                              

Capitalization ratios

                

Long-term debt, less amounts due currently

     126.4     115.1     118.8     88.5           28.0

EFCH shareholder’s equity

     (26.7     (15.3     (18.8     11.5              72.0   

Noncontrolling interests in subsidiaries

     0.3        0.2        —          —                —     
                                              

Total

     100.0     100.0     100.0     100.0           100.0
                                              
 

Short-term borrowings

   $ 1,221      $ 953      $ 900      $ 438            $ 818   

Long-term debt due currently

   $ 658      $ 302      $ 269      $ 202            $ 178   

 

(a) Fixed charges exceeded “earnings” (net loss) by $3.212 billion, $9.543 billion and $1.941 billion for the years ended December 31, 2010 and 2008 and for the period from October 11, 2007 through December 31, 2007, respectively.

Note: Although EFCH continued as the same legal entity after the Merger, its “Selected Financial Data” for periods preceding the Merger and for periods succeeding the Merger are presented as the consolidated financial statements of the “Predecessor” and the “Successor,” respectively. See Note 1 to Financial Statements “Basis of Presentation.” The consolidated financial statements of the Successor reflect the application of “purchase accounting.” Results for 2010 reflect the prospective adoption of amended guidance regarding consolidation accounting standards related to variable interest entities and amended guidance regarding transfers of financial assets that resulted in the accounts receivable securitization program no longer being accounted for as a sale of accounts receivable and the funding under the program now reported as short-term borrowings as discussed in Note 7 to Financial Statements. Results for 2010 were significantly impacted by a goodwill impairment charge as discussed in Note 2 to Financial Statements. Results in 2008 were significantly impacted by impairment charges related to goodwill, trade name and emission allowances intangible assets and natural gas-fueled generation facilities as discussed in Notes 2 and 3 to Financial Statements.

 

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Quarterly Information (Unaudited)

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

 

     First
Quarter
    Second
Quarter
    Third
Quarter (a)
    Fourth
Quarter
 

2010:

        

Operating revenues

   $ 1,999      $ 1,993      $ 2,607      $ 1,636   
                                

Net income (loss)

   $ 401      $ (458   $ (3,720   $ 247   

Net (income) loss attributable to noncontrolling interests

   $ (1   $ 1      $ —        $ —     
                                

Net income (loss) attributable to EFCH

   $ 400      $ (457   $ (3,720   $ 247   
                                
     First
Quarter (a)
    Second
Quarter
    Third
Quarter
    Fourth
Quarter
 

2009:

        

Operating revenues

   $ 1,766      $ 1.945      $ 2,433      $ 1,767   
                                

Net income (loss)

   $ 526      $ (107   $ (72   $ 168   
                                

Net income (loss) attributable to EFCH

   $ 526      $ (107   $ (72   $ 168   
                                

 

(a) Net income (loss) amounts include the effects of impairment charges related to goodwill (see Note 2 to Financial Statements).

 

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

The following discussion and analysis of EFCH’s financial condition and results of operations for the fiscal years ended December 31, 2010, 2009 and 2008 should be read in conjunction with Selected Financial Data and EFCH’s audited consolidated financial statements and the notes to those statements.

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

Business

EFCH, a wholly-owned subsidiary of EFH Corp., is a Dallas, Texas-based holding company that conducts its operations almost entirely 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 electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities and retail electricity sales. Key management activities, including commodity risk management, are performed on an integrated basis; consequently, there are no reportable business segments.

Significant Activities and Events

Natural Gas Prices and Long-Term Hedging Program — TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, the company has entered into market transactions involving natural gas-related financial instruments, and as of December 31, 2010, has effectively sold forward approximately 1.0 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 125,000 GWh at an assumed 8.0 market heat rate) for the period from January 1, 2011 through December 31, 2014 at weighted average annual hedge prices ranging from $7.19 per MMBtu to $7.80 per MMBtu.

These transactions, as well as forward power sales, have effectively hedged an estimated 62% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning January 1, 2011 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which is expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.

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

The company has entered into related put and call transactions (referred to as collars), primarily for 2014, that effectively hedge natural gas prices within a range. These transactions represented 11% of the positions in the long-term hedging program as of December 31, 2010, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. The company expects to use financial instruments, including collars, in future hedging activity under the long-term hedging program.

 

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The following table summarizes the natural gas hedges in the long-term hedging program as of December 31, 2010:

 

     Measure    2011      2012      2013      2014      Total  

Natural gas hedge volumes (a)

   mm MMBtu      ~220         ~398         ~282         ~110         ~1,010   

Weighted average hedge price (b)

   $/MMBtu      ~7.56         ~7.36         ~7.19         ~7.80         —     

Weighted average market price (c)

   $/MMBtu      ~4.55         ~5.08         ~5.33         ~5.49         —     

 

(a) Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity (i.e., delta position) of the derivatives. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 110 million MMBtu in 2014.
(b) Weighted average hedge prices are based on NYMEX Henry Hub prices of forward natural gas sales positions in the long-term hedging program (excluding the impact of offsetting purchases for rebalancing and pricing point basis transactions). Where collars are reflected, sales price represents the collar floor price.
(c) Based on NYMEX Henry Hub prices.

Changes in the fair value of the instruments in the long-term hedging program are being recorded as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities in the statement of income, which has and could continue to result in significant volatility in reported net income. Based on the size of the long-term hedging program as of December 31, 2010, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to $1.0 billion in pretax unrealized mark-to-market gains or losses.

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

 

     Year Ended December 31,  
     2010     2009     2008  

Effect of natural gas market price changes on open positions

   $ 2,317      $ 1,857      $ 2,483   

Reversals of previously recorded amounts on positions settled

     (1,152     (750     104   
                        

Total unrealized effect (pre-tax)

   $ 1,165      $ 1,107      $ 2,587   
                        

The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $3.143 billion and $1.978 billion as of December 31, 2010 and 2009, respectively. See discussion below under “Results of Operations” for realized net gains from hedging activities, which amounts are largely related to the long-term hedging program.

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

The significant cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program reflects declining forward market natural gas prices. Forward natural gas prices have generally trended downward since mid-2008 as shown in the table of forward NYMEX Henry Hub natural gas prices below. While the long-term hedging program is designed to mitigate the effect on earnings of low wholesale power prices, depressed forward natural gas prices are challenging to the long-term profitability of EFCH’s generation assets. Specifically, these lower natural gas prices and the correlated effect in ERCOT on wholesale electricity prices could have a material adverse impact on the overall profitability of EFCH’s generation assets for periods in which it has less significant hedge positions (i.e., beginning in 2013). In addition, a continuation or worsening of these market conditions would limit EFCH’s ability to hedge its wholesale electricity revenues at sufficient price levels to support its interest payments and debt maturities and could adversely impact EFCH’s ability to refinance the TCEH Revolving Credit Facility that matures in October 2013 and/or its substantial long-term debt that matures in 2014.

 

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Also see discussion below regarding the goodwill impairment charge recorded in the third quarter 2010.

 

     Forward Market Prices for Calendar Year ($/MMBtu) (a)  

Date

   2010 (b)      2011      2012      2013      2014  

June 30, 2008

   $ 11.24       $ 10.78       $ 10.74       $ 10.90       $ 11.12   

September 30, 2008

   $ 8.58       $ 8.54       $ 8.41       $ 8.30       $ 8.30   

December 31, 2008

   $ 7.13       $ 7.31       $ 7.23       $ 7.15       $ 7.15   

March 31, 2009

   $ 5.93       $ 6.67       $ 6.96       $ 7.11       $ 7.18   

June 30, 2009

   $ 6.06       $ 6.89       $ 7.16       $ 7.30       $ 7.43   

September 30, 2009

   $ 6.21       $ 6.87       $ 7.00       $ 7.06       $ 7.17   

December 31, 2009

   $ 5.79       $ 6.34       $ 6.53       $ 6.67       $ 6.84   

March 31, 2010

   $ 4.27       $ 5.34       $ 5.79       $ 6.07       $ 6.36   

June 30, 2010

   $ 4.82       $ 5.34       $ 5.68       $ 5.89       $ 6.10   

September 30, 2010

   $ 3.94       $ 4.44       $ 5.07       $ 5.29       $ 5.42   

December 31, 2010

   $ —         $ 4.55       $ 5.08       $ 5.33       $ 5.49   

 

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

As of December 31, 2010, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility — see discussion below under “Financial Condition — Liquidity and Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.

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

Impairment of Goodwill In the third quarter 2010, EFCH recorded a $4.1 billion noncash goodwill impairment charge (which was not deductible for income tax purposes). The write-off reflected the estimated effect of lower wholesale power prices on the enterprise value of EFCH, driven by the sustained decline in forward natural gas prices as discussed above. EFCH’s recorded goodwill totaled $6.2 billion as of December 31, 2010.

The noncash impairment charge did not cause EFCH to be in default under any of its debt covenants or impact counterparty trading agreements or have a material impact on liquidity.

See Note 2 to Financial Statements and “Application of Critical Accounting Policies” below for more information on goodwill impairment charges.

Liability Management Program — As of December 31, 2010, EFCH had $31.5 billion principal amount of debt outstanding, including short-term borrowings and $850 million pushed down from EFH Corp. The majority of outstanding debt matures during the period 2014 to 2017, and the TCEH Revolving Credit Facility matures in October 2013. EFH Corp. has implemented a liability management program focused on improving its balance sheet by reducing debt and extending debt maturities.

In 2010, debt exchanges, issuances and repurchases by TCEH as part of the liability management program resulted in the acquisition and cancellation of $2.3 billion principal amount of outstanding TCEH debt with due dates of 2015 and 2016 in exchange for $1.221 billion principal amount of new TCEH debt due 2021 and $343 million in cash. The cash represented the net proceeds from the issuance earlier in 2010 of an additional $350 million principal amount of new TCEH debt due 2021.

These transactions resulted in the capture of $700 million of debt discount.

See Note 8 to Financial Statements for further discussion of these transactions and transactions completed under EFH Corp.’s liability management program that resulted in the issuance of new EFH Corp. debt guaranteed by EFCH and the acquisition by EFH Corp. and EFIH of outstanding TCEH debt and outstanding EFH Corp. debt guaranteed by EFCH.

 

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Wholesale Market Design – Nodal Market — In accordance with a rule adopted by the PUCT in 2003, ERCOT developed a new wholesale market, using a stakeholder process, designed to assign congestion costs to the market participants causing the congestion. The nodal market design was implemented December 1, 2010. Under this new market design, ERCOT:

 

   

establishes nodes, which are metered locations across the ERCOT grid, for purposes of more granular price determination;

 

   

operates a voluntary “day-ahead electricity market” for forward sales and purchases of electricity and other related transactions, in addition to the existing “real-time market” that primarily functions to balance power consumption and generation;

 

   

establishes hub trading prices, which represent the average of certain node prices within four major geographic regions, at which participants can hedge or trade power under bilateral contracts;

 

   

establishes pricing for load-serving entities based on weighted-average node prices within new geographical load-zones, and

 

   

provides congestion revenue rights, which are instruments auctioned by ERCOT that allow market participants to hedge price differences between settlement points.

ERCOT previously had a zonal wholesale market structure consisting of four geographic zones. The new location-based congestion-management market is referred to as a “nodal” market because wholesale pricing differs across the various nodes on the transmission grid instead of across the geographic zones. There are over 500 nodes in the ERCOT market. The nodal market design was implemented in conjunction with transmission improvements designed to reduce current congestion. EFCH is fully certified to participate in both the “day-ahead” and “real-time markets.” Additionally, all of EFCH’s operational and mothballed generation assets and its qualified scheduling entities are certified and operate in the nodal market. While the initial implementation of the nodal market has not had a material impact on its profitability, EFCH cannot predict the ultimate impact of the market design on its operations or financial results, and it could ultimately have an adverse impact on the profitability and value of EFCH’s competitive business and/or its liquidity, particularly if such change ultimately results in lower revenue due to lower wholesale power prices, increased costs to service end-user electricity demand or increased collateral posting requirements with ERCOT. The opening of the nodal market resulted in an increase of approximately $200 million in the amount of letters of credit posted with ERCOT to support EFCH’s market participation.

As discussed above, the nodal market design includes the establishment of a “day-ahead market” and hub trading prices to facilitate hedging and trading of electricity by participants. Under the previous zonal market, volumes under EFCH’s nontrading bilateral purchase and sales contracts, including contracts intended as hedges, were scheduled as physical power with ERCOT and, therefore, reported gross as wholesale revenues or purchased power costs. In conjunction with the transition to the nodal market, unless the volumes represent physical deliveries to retail and wholesale customers or purchases from counterparties, these contracts are reported on a net basis in the income statement in net gain/(loss) from commodity hedging and trading activities. As a result of these changes, reported wholesale revenues and purchased power costs in 2011 will be materially less than amounts reported in prior periods.

TCEH Interest Rate Swap Transactions — As of December 31, 2010, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $15.80 billion principal amount of its senior secured debt maturing from 2011 to 2014. Swaps related to an aggregate $500 million principal amount of debt expired in 2010, and no swaps were entered into in 2010. Taking into consideration these swap transactions, 15% of EFCH’s total long-term debt portfolio as of December 31, 2010 was exposed to variable interest rate risk. As of December 31, 2010, TCEH also entered into interest rate basis swap transactions, which further reduce the fixed (through swaps) borrowing costs, related to an aggregate of $15.20 billion principal amount of senior secured debt, including swaps entered into in 2010 related to $2.55 billion principal amount of debt. Swaps related to an aggregate $3.60 billion principal amount of debt expired in 2010. EFCH may enter into additional interest rate hedges from time to time.

 

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Unrealized mark-to-market net gains and losses related to all TCEH interest rate swaps, which are reported in interest expense and related charges, totaled $207 million in net losses for the year ended December 31, 2010 and $696 million in net gains for the year ended December 31, 2009. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.419 billion and $1.212 billion as of December 31, 2010 and 2009, respectively, of which $105 million and $194 million (both pre-tax), respectively, was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. See discussion in Note 8 to Financial Statements regarding interest rate swap transactions.

Texas Generation Facilities Development — TCEH has completed a program to develop three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in Texas with a total estimated capacity of approximately 2,200 MW. The Sandow and first Oak Grove units achieved substantial completion (as defined in the EPC agreement) in the fourth quarter 2009, and the second Oak Grove unit achieved substantial completion (as defined in the EPC agreement) in the second quarter 2010. EFCH began depreciating the units and recognizing revenues and fuel costs for accounting purposes in those respective periods. Aggregate cash capital expenditures for these three units totaled approximately $3.25 billion including all construction, site preparation and mining development costs. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, totaled approximately $4.8 billion.

Idling of Natural Gas-Fueled Units — In December 2010, after receiving approval from ERCOT, EFCH retired eight previously mothballed natural gas-fueled units totaling 2,633 MW of capacity (2,777 MW installed nameplate capacity). EFCH also retired an additional natural gas-fueled unit with 112 MW of capacity (115 MW installed nameplate capacity) in December 2010 upon expiration of an RMR (operational standby) agreement (discussed below) related to the unit. No impairment was recorded as a result of the retirements. In September 2010, after receiving approval from ERCOT, EFCH mothballed (idled) four of its natural gas-fueled units totaling 1,856 MW of capacity (1,933 MW installed nameplate capacity). In 2009 EFCH retired 10 units totaling 2,114 MW of capacity (2,226 MW installed nameplate capacity), mothballed three units totaling 1,081 MW capacity (1,135 MW installed nameplate capacity) and entered into RMR agreements with ERCOT for two units totaling 627 MW capacity (655 MW installed nameplate capacity). Upon expiration of the RMR agreements in December 2010, EFCH retired the unit discussed above and mothballed the other unit.

As of December 31, 2010, TCEH’s operational fleet of natural gas-fueled generation facilities, which are generally used as peaking resources, consists of 14 units totaling 2,187 MW installed nameplate capacity, excluding eight units operated for unaffiliated parties and four mothballed units.

Global Climate Change and Other Environmental Matters — See Items 1 and 2, “Business and Properties – Environmental Regulations and Related Considerations” for discussion of global climate change and various other environmental matters and their effects on the company.

 

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KEY RISKS AND CHALLENGES

Following is a discussion of key risks and challenges facing management and the initiatives currently underway to manage such challenges. These matters involve risks that could have a material adverse effect on EFCH’s results of operations, liquidity or financial condition.

Substantial Leverage, Uncertain Financial Markets and Liquidity Risk

EFCH’s substantial leverage, resulting in large part from debt incurred to finance the Merger, requires significant cash flows to be dedicated to interest and principal payments and could adversely affect EFCH’s ability to raise additional capital to fund operations, limits EFCH’s ability to react to changes in the economy, its industry or its business, and exposes EFCH to interest rate risk to the extent not hedged. Principal amounts of short-term borrowings and long-term debt, including amounts due currently, totaled $31.5 billion as of December 31, 2010. Taking into consideration interest-rate swap transactions, as of December 31, 2010 approximately 85% of EFCH’s total long-term debt portfolio is subject to fixed interest rates, at a weighted average interest rate of 9.0%. Interest payments on long-term debt in 2011 (including amounts related to EFH Corp. pushed down debt) are expected to total approximately $2.2 billion, and principal payments on long-term debt are expected to total $644 million.

While EFCH believes its cash on hand and cash flow from operations combined with availability under existing credit facilities provide sufficient liquidity to fund current and projected expenses and capital requirements for 2011 (see “Financial Condition — Liquidity and Capital Resources” section below), there can be no assurance that counterparties to its credit facility and hedging arrangements will perform as expected and meet their obligations to EFCH. Failure of such counterparties to meet their obligations or substantial changes in financial markets, the economy, regulatory requirements, EFCH’s industry or EFCH’s operations could result in constraints in its liquidity. While traditional counterparties with physical assets to hedge, as well as financial institutions and other parties, continue to participate in the markets, as a result of the financial crisis that arose in 2008, there has been a reduction of available counterparties for EFCH’s hedging and trading activities, particularly for longer-dated transactions, which could impact EFCH’s ability to hedge its commodity price and interest rate exposure to desired levels at reasonable costs. See discussion of credit risk in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” discussion of available liquidity and liquidity effects of the long-term hedging program in “Financial Condition — Liquidity and Capital Resources” and discussion of potential impact of legislative rulemakings on the OTC derivatives market in “Significant Activities and Events — Financial Services Reform Legislation.”

In addition, as discussed above under “Significant Activities and Events — Natural Gas Prices and Long-Term Hedging Program,” a continuation or worsening of low forward natural gas prices (and the related low wholesale electricity prices in ERCOT) could also limit EFCH’s ability to hedge its wholesale electricity revenues at sufficient price levels to support its interest payments and debt maturities, result in further declines in the value of EFCH’s baseload generation assets and adversely impact EFCH’s efforts to refinance its substantial debt as discussed immediately below.

The TCEH Revolving Credit Facility matures in October 2013, and a substantial amount of EFCH’s long-term debt matures in the period from 2014 through 2017. EFCH is focused on improving the balance sheet and expects to opportunistically look for ways to reduce the amount and extend the maturity of its outstanding debt. Progress to date on this initiative includes the debt exchanges, issuances and repurchases completed in 2010 and 2009 by TCEH, EFH Corp. and EFIH and the August 2009 amendment to the Credit Agreement governing the TCEH Senior Secured Facilities that provided additional flexibility in restructuring debt obligations. See Note 8 to Financial Statements for additional discussion of these transactions.

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

 

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Natural Gas Price and Market Heat-Rate Exposure

Wholesale electricity prices in the ERCOT market generally move with the price of natural gas because marginal demand for electricity supply is generally met with natural gas-fueled generation facilities. Historically the price of natural gas has fluctuated due to changes in industrial demand, supply availability, weather effects and other economic and market factors and such prices have been very volatile in recent years. Since 2005, forward natural gas prices ranged from above $13 per MMBtu to below $4 per MMBtu. More recent declines in forward natural gas prices reflect discovery and increased drilling of shale gas deposits combined with lingering demand weakness associated with the economic recession. The wholesale market price of electricity divided by the market price of natural gas represents the market heat rate. Market heat rate movements also affect wholesale electricity prices. Market heat rate can be affected by a number of factors including the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity.

In contrast to EFCH’s natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating electricity from EFCH’s nuclear and lignite/coal-fueled facilities. All other factors being equal, these baseload generation assets, which provided the substantial majority of supply volumes in 2010, increase or decrease in value as natural gas prices and market heat rates rise or fall, respectively, because of the effect on wholesale electricity 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.

EFCH’s approach to managing electricity price risk focuses on the following:

 

   

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

 

   

continuing focus on cost management to better withstand gross margin volatility;

 

   

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

 

   

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

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

The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas and certain other commodity prices and market heat rates on realized pre-tax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH’s unhedged position and forward prices as of December 31, 2010, which for natural gas reflects estimates of electricity generation less amounts hedged through the long-term natural gas hedging program and amounts under existing wholesale and retail sales contracts. On a rolling twelve-month basis, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.

 

     Balance 2011(a)      2012      2013      2014  

$1.00/MMBtu change in gas price (b)

   $ ~5       $ ~80       $ ~305       $ ~490   

0.1/MMBtu/MWh change in market heat rate (c)

   $ ~4       $ ~32       $ ~44       $ ~46   

$1.00/gallon change in diesel fuel price

   $ —         $ ~1       $ ~48       $ ~40   

 

(a) Balance of 2011 is from February 1, 2011 through December 31, 2011.
(b) Assumes conversion of electricity positions based on an approximate 8.0 market heat rate with natural gas being on the margin 75% to 90% of the time (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated).
(c) Based on Houston Ship Channel natural gas prices as of December 31, 2010.

 

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EFCH’s market heat rate exposure is impacted by changes in the mix of generation assets resulting from generation capacity changes such as additions and retirements of generation facilities. Increased wind generation capacity could result in lower market heat rates. EFCH 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. EFCH mitigates market heat rate risk through retail and wholesale electricity sales contracts and shorter-term market heat rate hedging transactions. EFCH evaluates opportunities to mitigate market heat rate risk over extended periods through longer-term electricity sales contracts where practical considering pricing, credit, liquidity and related factors.

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

Competitive Retail Markets and Customer Retention

Competitive retail activity in Texas has resulted in retail customer churn. EFCH’s total retail customer counts rose 2% in 2008 but declined 3% in 2009 and 6% in 2010. Based upon 2010 results discussed below in “Results of Operations”, a 1% decline in residential customers would result in a decline in annual revenues of approximately $40 million. In responding to the competitive landscape in the ERCOT marketplace, EFCH is focusing on the following key initiatives:

 

   

Maintaining competitive pricing initiatives as evidenced by price reductions on most residential service plans;

 

   

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

 

   

Establishing TXU Energy as the most innovative retailer in the Texas market by continuing to develop tailored product offerings to meet customer needs. TXU Energy plans to invest $100 million over the five-year period beginning in 2008 (including $39 million invested through 2010) in retail initiatives aimed at helping consumers conserve energy and other demand-side management initiatives that are intended to moderate consumption and reduce peak demand for electricity, and

 

   

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

Volatile Energy Prices and Regulatory Risk

Natural gas prices rose to unprecedented levels in the latter part of 2005, reflecting a world-wide increase in energy prices compounded by hurricane-related infrastructure damage. The related rise in electricity prices elevated public awareness of energy costs and dampened customer demand. Natural gas prices remain subject to events that create price volatility, and while not reaching 2005 levels, forward natural gas prices rose substantially in 2007 and part of 2008 before falling in the second half of 2008 through most of 2010. 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. EFCH 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 entities should continue to take actions that encourage competition in the industry. Regulatory and/or legislative intervention could materially affect the competitive electricity industry in ERCOT, including disrupting the relationship between natural gas prices and electricity prices, which could materially impact the results of EFCH’s long-term hedging program. (Also see “Regulatory Matters — Sunset Review.”) EFCH continues to closely monitor any potential legislative and regulatory changes and work with legislators and regulators, providing them information on the market and related matters.

 

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Financial Services Reform Legislation

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

Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives market. The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that EFCH uses to hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However, entities are exempt from these clearing requirements if they (i) are not “Swap Dealers” or “Major Swap Participants” as will be defined in the rulemakings and (ii) use the swaps to hedge or mitigate commercial risk. The proposed definition of Swap Dealer is broad and will, as drafted, include many end users. EFCH is evaluating whether or not the type of asset-backed OTC derivatives that it uses to hedge commodity and interest rate risk is exempt from the clearing requirements. Existing swaps are grandfathered from the clearing requirements. The legislation mandates significant reporting and compliance requirements for any entity that is determined to be a Swap Dealer or Major Swap Participant.

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

EFCH cannot predict the outcome of the rulemakings to implement the OTC derivative market provisions of the Financial Reform Act. These rulemakings could negatively affect EFCH’s ability to hedge its commodity and interest rate risks. Accordingly, EFCH continues to closely monitor the rulemakings and any other potential legislative and regulatory changes and work with regulators and legislators, providing them information on EFCH’s operations, the types of transactions in which EFCH engages, EFCH’s concerns regarding potential regulatory impacts, market characteristics and related matters.

New and Changing Environmental Regulations

EFCH is subject to various environmental laws and regulations related to SO2, NOx and mercury as well as other emissions that impact air and water quality. EFCH believes it is in compliance with all current laws and regulations, but regulatory authorities continue to evaluate existing requirements and consider proposals for changes. If EFCH makes any major modifications to its power generation facilities, it may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the Clean Air Act. Any such modifications would likely result in substantial additional capital expenditures. (See Note 9 to Financial Statements for discussion of “Litigation Related to Generation Facilities,” “Regulatory Reviews” and “Environmental Contingencies.”)

 

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EFCH also continues to closely monitor any potential legislative, regulatory and judicial changes pertaining to global climate change. In view of the fact that a substantial portion of EFCH’s generation portfolio consists of lignite/coal-fueled generation facilities, its results of operations, liquidity or financial condition could be materially adversely affected by the enactment of any legislation, regulation or judicial action that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes on entities that produce GHG emissions, or that establishes federal renewable energy portfolio standards. For example, federal, state or regional legislation or regulation addressing global climate change could result in EFCH either incurring increased material costs to reduce its GHG emissions or to procure emission allowances or credits to comply with a mandatory cap-and-trade emissions reduction program. See further discussion under Items 1 and 2, “Business and Properties — Environmental Regulations and Related Considerations.”

Exposures Related to Nuclear Asset Outages

EFCH’s nuclear assets are comprised of two generation units at Comanche Peak, each with an installed nameplate capacity of 1,150 MW. The Comanche Peak plant represents approximately 15% of EFCH’s total generation capacity. The nuclear generation units represent EFCH’s lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage, the unfavorable impact to pretax earnings is estimated (based upon market prices as of December 31, 2010) to be approximately $2 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 9 to Financial Statements.

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

EFCH participates in industry groups and with regulators to remain current on the latest developments in nuclear safety, operation and maintenance and on emerging threats and mitigating techniques. These groups include, but are not limited to, the NRC and the Institute of Nuclear Power Operations (INPO), EFCH also applies the knowledge gained by continuing to invest in technology, processes and services to improve its operations and detect, mitigate and protect its nuclear generation assets. 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.

Cyber Security and Infrastructure Protection Risk

A breach of cyber/data security measures that impairs EFCH’s information technology infrastructure could disrupt normal business operations and affect its ability to control its generation assets, access retail customer information and limit communication with third parties. Any loss of confidential or proprietary data through a breach could materially and adversely affect EFCH’s reputation, expose the company to legal claims or impair its ability to execute on business strategies.

EFCH participates in industry groups and with regulators to remain current on emerging threats and mitigating techniques. These groups include, but are not limited to: the US Cyber Emergency Response Team, the National Electric Sector Cyber Security Organization, the NRC and NERC. EFCH also applies the knowledge gained by continuing to invest in technology, processes and services to detect, mitigate and protect its cyber assets. These investments include upgrades to network architecture, regular intrusion detection monitoring and compliance with emerging industry regulation.

 

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APPLICATION OF CRITICAL ACCOUNTING POLICIES

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

Purchase Accounting

In 2007, the Merger was accounted for under purchase accounting, whereby the purchase price of the transaction was allocated to EFCH’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 accounting standards related to the determination of fair value (see Note 11 to Financial Statements) and reflect significant assumptions and judgments. Material valuation inputs for long-lived assets and liabilities included forward electricity and natural gas price curves and market heat rates, discount rates, nonperformance risk adjustments related to liabilities, retail customer attrition rates, generation plant operating and construction costs and asset lives. The valuations reflected considerations unique to the competitive wholesale power market in ERCOT as well as EFCH’s assets. For example, the valuation of the baseload generation facilities considered EFCH’s lignite fuel reserves and mining capabilities.

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

The excess of the purchase price over the estimated fair values of the net assets acquired was recorded as goodwill. The goodwill amount recorded upon finalization of purchase accounting totaled $18.3 billion. Purchase accounting impacts, including goodwill recognition, have been “pushed down”, resulting in the assets and liabilities of EFCH 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 EFCH’s operations as of the date of the Merger. In accordance with accounting guidance related to goodwill and other intangible assets, goodwill is not amortized to net income, but is required to be tested for impairment at least annually. Management believes the drivers of the goodwill amount recorded by EFCH included the incremental value of the future cash flow potential of the baseload generation facilities, including facilities under construction, over the values assigned to those assets under purchase accounting rules, considering the market-pricing mechanisms and growth potential in the ERCOT market, as well as the value derived from the scale of the retail business. Also see discussion below under “Impairment of Assets.”

In the third quarter 2010, EFCH recorded a goodwill impairment charge totaling $4.1 billion. In the first quarter 2009 and fourth quarter 2008, EFCH recorded goodwill impairment charges totaling $8.070 billion. The $70 million charge in the first quarter 2009 resulted from the completion of the previously estimated fair value calculations supporting the initial $8.0 billion goodwill impairment charge that was recorded in the fourth quarter 2008. See discussion immediately below under “Impairment of Goodwill and Other Long-Lived Assets.”

 

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Push Down of Merger-Related Debt

Merger-related debt of EFH Corp. and its subsidiaries consists of debt issued or existing as of the time of the Merger. Debt issued in exchange for Merger-related debt is considered Merger-related. Debt issuances are considered Merger-related debt to the extent the proceeds are used to repurchase Merger-related debt. Merger-related debt that is fully and unconditionally guaranteed on a joint and several basis by EFCH and EFIH is subject to push down in accordance with SEC Staff Accounting Bulletin Topic 5-J, and as a result, a portion of such debt and related interest expense is reflected in the financial statements of EFCH. The amount reflected on EFCH’s balance sheet represents 50% of the EFH Corp. Merger-related debt it has guaranteed. This percentage reflects the fact that as of the time of the Merger, the equity investments of EFCH and EFIH in their respective operating subsidiaries were essentially equal amounts. Because payment of principal and interest on the notes is the responsibility of EFH Corp., EFCH records the settlement of such amounts as noncash capital contributions from EFH Corp. See Note 8 to Financial Statements.

Impairment of Goodwill and Other Long-Lived Assets

EFCH evaluates long-lived assets (including intangible assets with finite lives) for impairment, in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. One of those indications is a current expectation that “more likely than not” a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life (as was the case for the natural gas-fueled generation assets in 2008 discussed below). For EFCH’s baseload generation assets, another possible indication would be an expected long-term decline in natural gas prices and/or market heat rates. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows related to an asset or group of assets. Further, the unique nature of EFCH’s property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual plants that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing.

Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually (EFCH has selected December 1) or whenever events or changes in circumstances indicate an impairment may exist, such as the possible impairments to long-lived assets discussed above. As required by accounting guidance related to goodwill and other intangible assets, EFCH has allocated goodwill to its reporting unit, which essentially consists of TCEH and goodwill impairment testing is performed at the reporting unit level. Under this goodwill impairment analysis, if at the assessment date, a reporting unit’s carrying value exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair values of the reporting unit’s operating assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill amount is then compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied goodwill amount is written off as an impairment charge.

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

 

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The 2010 annual impairment testing performed as of December 1, 2010 for goodwill and intangible assets with indefinite useful lives in accordance with accounting guidance resulted in no impairment. The goodwill testing determined that the carrying value of EFCH exceeded its estimated fair value (enterprise value), so the estimated enterprise value of EFCH was compared to the estimated fair values of its operating assets and liabilities. This additional testing indicated that the recorded goodwill amount did not exceed the estimated implied goodwill amount, and thus no additional goodwill impairment was indicated beyond the charge recorded in the third quarter 2010 as discussed immediately below. Key variables in the tests included forward natural gas prices, electricity prices, market heat rates and discount rates, assumptions regarding each of which could have a significant effect on valuations. Because of the volatility of these factors, EFCH cannot predict the likelihood of any future impairment.

See Note 2 to Financial Statements for a discussion of the goodwill impairment charges of $4.1 billion recorded in 2010 and $8.070 billion recorded largely in 2008. The total $12.170 billion of impairment charges represented almost 67% of EFCH’s goodwill balance resulting from purchase accounting for the Merger and reflected a decline of approximately 35% in the estimated enterprise value of TCEH as of December 1, 2010 from the indicated value at the October 2007 Merger date. The impairment in 2010 reflected the estimated effect of lower wholesale power prices on the enterprise value of EFCH, driven by the sustained decline in forward natural gas prices. The impairment in 2008 primarily arose from the dislocation in the capital markets that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies in the second half of 2008. Also see Note 2 to Financial Statements for discussion of the impairment charge of $481 million ($310 million after-tax) related to the trade name intangible asset recorded in the fourth quarter 2008. The estimated fair value of this intangible asset is based on an assumed royalty methodology. Impairment charges totaling $501 million in 2008 related to environmental allowances and credits are also discussed in Note 2 to Financial Statements.

In 2008, EFCH recorded an impairment charge of $229 million ($147 million after-tax) related to its natural gas-fueled generation facilities. The natural gas-fueled generation units are generally operated to meet peak demands for electricity, and the facilities were tested for impairment as an asset group. See Note 3 to Financial Statements for a discussion of the impairment. The estimated impairment was based on numerous judgments including forecasted production, forward prices of natural gas and electricity, overall generation availability in ERCOT and ERCOT grid congestion. See “Business — Significant Activities and Events” for discussion of natural gas-fueled units mothballed (idled) or retired in 2009 consistent with the factors that resulted in the impairment.

Derivative Instruments and Mark-to-Market Accounting

EFCH 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 accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.

Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. EFCH estimates fair value as described in Note 11 to Financial Statements and discussed under “Fair Value Measurements” below.

 

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Accounting standards related to derivative instruments and hedging activities allow for “normal” purchase or sale elections and hedge accounting designations at the inception of the contract, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. “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 if the election as normal is made. Hedge accounting designations are made with the intent to match the accounting recognition of the contract’s financial performance to that of the transaction the contract is intended to hedge.

Under hedge accounting, changes in fair value of instruments designated as cash flow hedges are recorded in other comprehensive income with an offset to derivative assets and liabilities to the extent the change in value is effective; that is, it mirrors the offsetting change in fair value of the forecasted hedged transaction. Changes in value that represent ineffectiveness of the hedge are recognized in net income immediately, and the effective portion of changes in fair value initially recorded in other comprehensive income are recognized in net income in the period that the hedged transactions are recognized. Although as of December 31, 2010, EFCH does not have any derivatives designated as cash flow or fair value hedges, EFCH continually assesses potential hedge elections and could designate positions as cash flow hedges in the future. In March 2007, the instruments making up a significant portion of the long-term hedging program that were previously designated as cash flow hedges were dedesignated as allowed under accounting standards related to derivative instruments and hedging activities, and subsequent changes in their fair value are being marked-to-market in net income. In addition, in August 2008, interest rate swap transactions in effect at that time were dedesignated as cash flow hedges in accordance with accounting standards, and subsequent changes in their fair value are being marked-to-market in net income. See further discussion of the long-term hedging program and interest rate swap transactions under “Business — Significant Activities and Events.”

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

 

     Year Ended December 31,  
     2010     2009     2008  

Amounts recognized in net income (loss) (after-tax):

      

Unrealized net gains on positions marked-to-market in net income (a)

   $ 1,257      $ 1,573      $ 517   

Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the period (a)

     (607     (333     25   

Unrealized ineffectiveness net losses on positions accounted for as cash flow hedges

     —          —          (3

Reversals of previously recognized unrealized net losses related to cash flow hedge positions settled in the period

     1        1        —     
                        

Total

   $ 651      $ 1,241      $ 539   
                        

Amounts recognized in other comprehensive income (after-tax):

      

Net losses in fair value of positions accounted for as cash flow hedges

   $ —        $ (20   $ (181

Net losses on cash flow hedge positions recognized in net income to offset hedged transactions

     59        129        122   
                        

Total

   $ 59      $ 109      $ (59
                        

 

(a) Amounts for 2010, 2009 and 2008 include $785 million, $788 million and $1.503 billion in net after-tax gains related to commodity positions, respectively, and $135 million in net after-tax losses, $452 million in net after-tax gains and $960 million in net after-tax losses related to interest rate swaps, respectively.

 

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

 

     December 31,
2010
    December 31,
2009
 

Commodity contract assets

   $ 4,705      $ 3,860   

Commodity contract liabilities

   $ (1,608   $ (2,146

Interest rate swap assets

   $ 6      $ 12   

Interest rate swap liabilities

   $ (1,425   $ (1,224

Net accumulated other comprehensive loss included in shareholders’ equity (amounts after-tax)

   $ (68   $ (127

EFCH reports derivative assets and liabilities in the balance sheet without taking into consideration netting arrangements it has with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the balance sheet. See Note 11 to Financial Statements.

Fair Value Measurements

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

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

 

   

quoted prices for similar assets or liabilities in active markets;

 

   

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

 

   

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

 

   

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

Examples of Level 2 valuation inputs utilized include over-the-counter broker quotes and quoted prices for similar assets or liabilities that are corroborated by correlation or through statistical relationships between different price curves. For example, certain physical power derivatives are executed for a particular location at specific time periods that might not have active markets; however, an active market might exist for such derivatives for a different time period at the same location. EFCH utilizes correlation techniques to compare prices for inputs at both time periods to provide a basis to value the non-active derivative. (See Note 11 to Financial Statements for additional discussion of how broker quotes are utilized.)

Level 3 valuations generally apply to EFCH’s more complex long-term power purchases and sales agreements, including longer-term wind and other power purchase and sales contracts and certain natural gas positions (collars) in the long-term hedging program. Level 3 valuations use largely unobservable inputs, with little or no supporting market activity, and assets and liabilities are classified as Level 3 if such inputs are significant to the fair value determination. EFCH uses the most meaningful information available from the market, combined with its own internally developed valuation methodologies, to develop its best estimate of fair value. The determination of fair value for Level 3 assets and liabilities requires significant management judgment and estimation.

 

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

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

Level 3 assets totaled $401 million and $350 million as of December 31, 2010 and 2009, respectively, and represented approximately 8% of the assets measured at fair value in both years, or approximately 1% and less than 1% of total assets, respectively. Level 3 liabilities totaled $59 million and $269 million as of December 31, 2010 and 2009, respectively, and represented approximately 2% and 8%, respectively, of the liabilities measured at fair value, or less than 1% of total liabilities.

Valuations of several of EFCH’s Level 3 assets and liabilities are sensitive to changes in discount rates, option-pricing model inputs such as volatility factors and credit risk adjustments. As of December 31, 2010, a $5.00 per MWh change in electricity price assumptions across unobservable inputs would cause an approximate $5 million change in net Level 3 assets. A 10% change in coal price assumptions across unobservable inputs would cause an approximate $1 million change in net Level 3 assets. See Note 11 to Financial Statements for additional information about fair value measurements, including a table presenting the changes in Level 3 assets and liabilities for the twelve months ended December 31, 2010, 2009 and 2008.

Variable Interest Entities

A variable interest entity (VIE) is an entity with which EFCH has a relationship or arrangement that indicates some level of control over the entity or results in economic risks to EFCH. Determining whether or not to consolidate a VIE requires interpretation of accounting rules and their application to existing business relationships and underlying agreements. Amended accounting rules related to VIEs became effective January 1, 2010. In determining the appropriateness of consolidation of a VIE, EFCH evaluates its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. EFCH also examines the nature of any related party relationships among the interest holders of the VIE and the rights granted to the interest holders of the VIE to determine whether EFCH has the right or obligation to absorb profit and loss from the VIE and the power to direct the significant activities of the VIE. See Note 18 to Financial Statements for information regarding EFCH’s consolidated variable interest entities.

Revenue Recognition

EFCH’s revenue includes an estimate for unbilled revenue that represents estimated daily kWh consumption after the meter read date to the end of the period multiplied by the applicable billing rates. Estimated daily kWh usage is derived using historical kWh usage information adjusted for weather and other measurable factors affecting consumption. Calculations of unbilled revenues during certain interim periods are generally subject to more estimation variability because of seasonal changes in demand. Accrued unbilled revenues totaled $297 million, $468 million and $427 million as of December 31, 2010, 2009 and 2008, respectively.

 

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Accounting for Contingencies

EFCH’s financial results may be affected by judgments and estimates related to loss contingencies. A significant contingency that EFCH accounts for is the loss associated with uncollectible trade accounts receivable. The determination of such bad debt expense is based on factors such as historical write-off experience, aging of accounts receivable balances, changes in operating practices, regulatory rulings, general economic conditions, effects of hurricanes and other natural disasters and customers’ behaviors. Changes in customer count and mix due to competitive activity and seasonal variations in amounts billed add to the complexity of the estimation process. Historical results alone are not always indicative of future results, causing management to consider potential changes in customer behavior and make judgments about the collectability of accounts receivable. Bad debt expense, the substantial majority of which relates to EFCH’s retail operations, totaled $108 million, $116 million and $81 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Litigation contingencies also may require significant judgment in estimating amounts to accrue. EFCH accrues liabilities for litigation contingencies when such liabilities are considered probable of occurring and the amount is reasonably estimable. No significant amounts have been accrued for such contingencies during the three-year period ended December 31, 2010. See Item 3, “Legal Proceedings” for discussion of major litigation.

Accounting for Income Taxes

EFCH’s income tax expense and related balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, EFCH’s forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. EFH Corp.’s income tax returns are regularly subject to examination by applicable tax authorities. In management’s opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that may be owed as a result of any examination. See Notes 1, 4 and 5 to Financial Statements for discussion of income tax matters.

Depreciation and Amortization

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

The estimated remaining lives range from 22 to 59 years for the lignite/coal- and nuclear-fueled generation units.

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 2 to Financial Statements for additional information.

Defined Benefit Pension Plans and OPEB Plans

Subsidiaries of EFCH 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 EFCH 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 EFCH. Reported costs of providing noncontributory defined pension benefits and OPEB are dependent upon numerous factors, assumptions and estimates.

 

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

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

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

 

     Year Ended December 31,  
     2010     2009     2008  

Pension costs

   $ 28      $ 13      $ 6   

OPEB costs

     11        9        8   
                        

Total benefit costs and net amounts recognized as expense

   $ 39      $ 22      $ 14   
                        

Discount rate (a)

     5.90     6.90     6.55

Funding of pension and OPEB plans (b)

   $ 1      $ 19      $ 1   

 

(a) Discount rate for OPEB was 6.85% in 2009.
(b) The increase in 2009 reflects transfers of investments related to the salary deferral and supplemental retirement plans.

See Note 16 to Financial Statements regarding other disclosures related to pension and OPEB obligations.

 

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RESULTS OF OPERATIONS

Effects of Change in Wholesale Electricity Market

As discussed above under “Significant Activities and Events,” the nodal wholesale market design implemented by ERCOT in December 2010 resulted in operational changes that facilitate hedging and trading of power. As part of ERCOT’s transition to a nodal wholesale market, volumes under nontrading bilateral purchase and sales contracts are no longer scheduled as physical power with ERCOT. As a result of these changes in market operations, reported wholesale revenues and purchased power costs in 2011 will be materially less than amounts reported in prior periods. Effective with the nodal market implementation, if volumes delivered to EFCH’s retail and wholesale customers are less than its generation volumes (as determined on a daily settlement basis), EFCH records additional wholesale revenues. Conversely, if volumes delivered to EFCH’s retail and wholesale customers exceed its generation volumes, EFCH records additional purchased power costs. The resulting additional wholesale revenues or purchased power costs are offset in net gain/(loss) from commodity hedging and trading activities.

Sales Volume and Customer Count Data

 

     Year Ended December 31,     2010
%  Change
    2009
%  Change
 
     2010     2009     2008      

Sales volumes:

          

Retail electricity sales volumes — (GWh):

          

Residential

     28,208        28,046        28,135        0.6        (0.3

Small business (a)

     8,042        7,962        7,363        1.0        8.1   

Large business and other customers

     15,339        14,573        13,945        5.3        4.5   
                            

Total retail electricity

     51,589        50,581        49,443        2.0        2.3   

Wholesale electricity sales volumes (b)

     51,359        42,320        46,743        21.4        (9.5
                            

Total sales volumes

     102,948        92,901        96,186        10.8        (3.4
                            

Average volume (kWh) per residential customer (c)

     15,532        14,855        14,780        4.6        0.5   

Weather (North Texas average) – percent of normal (d):

          

Cooling degree days

     108.9     98.1     107.3     11.0        (8.6

Heating degree days

     116.6     105.8     98.3     10.2        7.6   

Customer counts:

          

Retail electricity customers (end of period and in thousands) (e):

          

Residential

     1,771        1,862        1,914        (4.9     (2.7

Small business (a)

     217        262        275        (17.2     (4.7

Large business and other customers

     20        23        25        (13.0     (8.0
                            

Total retail electricity customers

     2,008        2,147        2,214        (6.5     (3.0
                            

 

(a) Customers with demand of less than 1 MW annually.
(b) Includes net amounts related to sales and purchases of balancing energy in the “real-time market.”
(c) Calculated using average number of customers for the period.
(d) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). Normal is defined as the average over a 10-year period.
(e) Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number of meters does not reflect the number of individual customers. The year ended December 31, 2008 reflects reclassification of 18 thousand meters from residential to small business to conform to current presentation.

 

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Revenue and Commodity Hedging and Trading Activities

 

     Year Ended December 31,     2010
%  Change
    2009
%  Change
 
     2010     2009     2008      

Operating revenues:

          

Retail electricity revenues:

          

Residential

   $ 3,663      $ 3,806      $ 3,782        (3.8     0.6   

Small business (a)

     1,052        1,164        1,099        (9.6     5.9   

Large business and other customers

     1,211        1,261        1,447        (4.0     (12.9
                            

Total retail electricity revenues

     5,926        6,231        6,328        (4.9     (1.5

Wholesale electricity revenues (b) (c)

     2,005        1,383        3,115        45.0        (55.6

Amortization of intangibles (d)

     16        5        (36     —          —     

Other operating revenues

     288        292        380        (1.4     (23.2
                            

Total operating revenues

   $ 8,235      $ 7,911      $ 9,787        4.1        (19.2
                            

Net gain from commodity hedging and trading activities:

          

Unrealized net gains from changes in fair value

   $ 2,162      $ 1,741      $ 2,290        24.2        (24.0

Unrealized net losses representing reversals of previously recognized fair values of positions settled in the current period

     (1,009     (464     (9     —          —     

Realized net gains (losses) on settled positions

     1,008        459        (97     —          —     
                            

Total gain

   $ 2,161      $ 1,736      $ 2,184        24.5        (20.5
                            

 

(a) Customers with demand of less than 1 MW annually.
(b) Upon settlement of physical derivative power sales and purchase contracts that are marked-to-market in net income, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result, these line item amounts include a noncash component, which the company considers “unrealized.” (The offsetting differences between contract and market prices are reported in net gain from commodity hedging and trading activities.) These amounts are as follows:

 

     Year Ended December 31,  
     2010     2009     2008  

Reported in revenues

   $ (28   $ (166   $ 42   

Reported in fuel and purchased power costs

     96        114        6   
                        

Net gain (loss)

   $ 68      $ (52   $ 48   
                        

 

(c) Includes net amounts related to sales and purchases of balancing energy in the “real-time market.”
(d) Represents amortization of the intangible net asset value of retail and wholesale power sales agreements resulting from purchase accounting.

 

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Production, Purchased Power and Delivery Cost Data

 

     Year Ended December 31,     2010
%  Change
    2009
%  Change
 
     2010     2009     2008      

Fuel, purchased power costs and delivery fees ($ millions):

          

Nuclear fuel

   $ 159      $ 121 (e)    $ 95        31.4        27.4   

Lignite/coal

     910        670        640        35.8        4.7   
                            

Total baseload fuel

     1,069        791        735        35.1        7.6   

Natural gas fuel and purchased power (a)

     1,502        1,224        2,881        22.7        (57.5

Amortization of intangibles (b)

     161        285 (e)      318        (43.5     (10.4

Other costs

     187        202        351        (7.4     (42.5
                            

Fuel and purchased power costs

     2,919        2,502        4,285        16.7        (41.6

Delivery fees

     1,452        1,432        1,315        1.4        8.9   
                            

Total

   $ 4,371      $ 3,934      $ 5,600        11.1        (29.8
                            

Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh:

          

Nuclear fuel

   $ 7.89      $ 5.98 (e)    $ 4.92        31.9        21.5   

Lignite/coal (c)

   $ 19.19      $ 16.47      $ 15.80        16.5        4.2   

Natural gas fuel and purchased power

   $ 52.37      $ 44.36      $ 81.99        18.1        (45.9

Delivery fees per MWh

   $ 28.06      $ 28.09      $ 26.33        (0.1     6.7   

Production and purchased power volumes (GWh):

          

Nuclear

     20,208        20,104        19,218        0.5        4.6   

Lignite/coal

     54,775        45,684        44,923        19.9        1.7   
                            

Total baseload generation

     74,983        65,788        64,141        14.0        2.6   

Natural gas-fueled generation

     1,648        2,447        4,122        (32.7     (40.6

Purchased power (d)

     26,317        24,666        27,923        6.7        (11.7
                            

Total energy supply volumes

     102,948        92,901        96,186        10.8        (3.4
                            

Baseload capacity factors:

          

Nuclear

     100.3     100.0     95.2     0.3        5.0   

Lignite/coal

     82.2     86.5     87.6     (5.0     (1.3

Total baseload

     86.6     90.3     89.8     (4.1     0.6   

 

(a) See note (b) on previous page.
(b) Represents amortization of the intangible net asset values of emission credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting.
(c) Includes 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.
(d) Includes amounts related to line loss and power imbalances.
(e) Reflects reclassification to correct amortization.

 

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Financial Results — Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Operating revenues increased $324 million, or 4%, to $8.235 billion in 2010.

Wholesale electricity revenues increased $622 million, or 45%, to $2.005 billion in 2010. A 21% increase in wholesale electricity sales volumes, reflecting production from the new generation units and increased sales to third-party REPs, increased revenues by $332 million. An 8% increase in average wholesale electricity prices, reflecting higher natural gas prices at the time the underlying contracts were executed, increased revenues by $149 million. The balance of the revenue increase reflected lower unrealized losses in 2010 related to physical derivative commodity sales contracts as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above.

Retail electricity revenues decreased $305 million, or 5%, to $5.926 billion and reflected the following:

 

   

Lower average pricing decreased revenues by $429 million reflecting declines in both the business and residential markets. Lower average pricing is reflective of competitive activity in a lower wholesale power price environment and a change in business customer mix.

 

   

A 2% increase in sales volumes increased revenues by $124 million reflecting increases in both the business and residential markets. A 4% increase in business markets sales volumes reflected a change in customer mix resulting from contracts executed with new customers. Residential sales volumes increased 1% reflecting higher average consumption driven by colder winter weather and hotter summer weather, partially offset by a decline in residential customer counts.

Fuel, purchased power costs and delivery fees increased $437 million, or 11%, to $4.371 billion in 2010. Higher purchased power costs contributed $255 million to the increase and reflected increased planned generation unit outages and higher retail demand, as well as increased prices driven by the effect of higher natural gas prices at the time the underlying contracts were executed. Other factors contributing to the increase included $126 million in higher lignite/coal costs at existing plants, reflecting higher purchased coal transportation and commodity costs, $114 million in increased lignite fuel costs related to production from the new generation units, a $39 million increase in nuclear fuel expense reflecting increased uranium and conversion costs, a $23 million increase in natural gas and fuel oil costs driven by higher prices, $20 million in higher delivery fees, reflecting increased retail sales volumes and tariffs, and an $18 million decrease in unrealized gains related to physical derivative commodity purchase contracts. These increases were partially offset by $124 million in lower amortization of the intangible net asset values (including the stepped-up value of nuclear fuel) resulting from purchase accounting, which reflected expiration of commodity contracts and consumption of the nuclear fuel.

Overall baseload generation production increased 14% in 2010 driven by production from the new generation units. Nuclear production increased 1%, and existing lignite/coal-fueled generation decreased 2% driven by increased economic backdown.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities for the years ended December 31, 2010 and 2009, which totaled $2.161 billion and $1.736 billion, respectively:

Year Ended December 31, 2010Unrealized mark-to-market net gains totaling $1.153 billion included:

 

   

$1.157 billion in net gains related to hedge positions, which includes $2.133 billion in net gains from changes in fair value, driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $976 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

 

   

$4 million in net losses related to trading positions, which includes $29 million in net gains from changes in fair value, and $33 million in net losses that represent reversals of previously recorded net gains on positions settled in the period.

 

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Realized net gains totaling $1.008 billion included:

 

   

$961 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

 

   

$47 million in net gains related to trading positions.

Year Ended December 31, 2009Unrealized mark-to-market net gains totaling $1.277 billion included:

 

   

$1.260 billion in net gains related to hedge positions, which includes $1.719 billion in net gains from changes in fair value, driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $459 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

 

   

$17 million in net gains related to trading positions, which includes $22 million in net gains from changes in fair value, and $5 million in net losses that represent reversals of previously recorded net gains on positions settled in the period.

Realized net gains totaling $459 million included:

 

   

$449 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

 

   

$10 million in net gains related to trading positions.

Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $68 million in net gains in 2010 and $52 million in net losses in 2009.

Operating costs increased $144 million, or 21%, to $837 million in 2010. The increase reflected $90 million in incremental expense related to the new generation units. The balance of the increase was driven by installation and maintenance of emissions control equipment at the existing lignite/coal-fueled generation facilities and higher maintenance costs at both the nuclear and existing lignite/coal-fueled facilities reflecting timing and scope of project work.

Depreciation and amortization increased $208 million, or 18%, to $1.380 billion in 2010. The increase reflected $162 million in incremental expense related to the new generation units and associated mining operations. The balance of the increase was driven by equipment additions.

SG&A expenses decreased $19 million, or 3%, to $722 million in 2010. The decrease reflected:

 

   

$31 million in lower transition costs associated with outsourced services and the retail customer information management system implemented in 2009;

 

   

$16 million in lower employee compensation-related expense in 2010;

 

   

$12 million of accounts receivable securitization program fees that are reported in 2010 as interest expense and related charges (see Note 7 to Financial Statements), and

 

   

$8 million in lower bad debt expense,

partially offset by $46 million of costs allocated from corporate in 2010, principally fees paid to the Sponsor Group.

See Note 2 to Financial Statements for discussion of the $4.1 billion impairment of goodwill recorded in 2010 and of the $70 million impairment of goodwill recorded in 2009 that resulted from the completion of fair value calculations supporting a goodwill impairment charge recorded in the fourth quarter of 2008.

 

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Other income totaled $903 million in 2010 and $59 million in 2009. Other income in 2010 included debt extinguishment gains of $687 million, a $116 million gain on termination of a power sales contract, a $44 million gain on the sale of land and related water rights and a $37 million gain associated with the sale of interests in a natural gas gathering pipeline business. The 2009 amount included a $23 million reversal of a use tax accrual, an $11 million reversal of exit liabilities recorded in connection with the termination of outsourcing arrangements and $25 million in several individually immaterial items. Other deductions totaled $18 million in 2010 and $63 million in 2009. The 2010 amount included several individually immaterial items. The 2009 amount included $34 million in charges for the impairment of land expected to be sold, $7 million in severance charges and other individually immaterial miscellaneous expenses. See Note 6 to Financial Statements for additional details.

Interest income increased $28 million, or 45%, to $90 million in 2010 reflecting higher notes receivable balances from affiliates.

Interest expense and related charges increased by $946 million, or 45%, to $3.067 billion in 2010 reflecting a $207 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $696 million net gain in 2009 and a $214 million decrease in capitalized interest due to completion of new generation facility construction activities, partially offset by a $96 million decrease in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges and $55 million in lower average borrowings.

Income tax expense totaled $318 million in 2010 compared to $351 million in 2009. Excluding the $4.1 billion and $70 million nondeductible goodwill impairment charges in 2010 and 2009, respectively, the effective tax rates were 35.8% and 37.5%, respectively. The decrease in the rate reflected lower interest accrued on uncertain tax positions in 2010.

Results decreased $4.045 billion in 2010 to a loss of $3.530 billion reflecting the $4.1 billion goodwill impairment charge and increased interest expense, partially offset by debt extinguishment gains and an increase in net gains from commodity hedging and trading activities.

 

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

Operating revenues decreased $1.876 billion, or 19%, to $7.911 billion in 2009.

Wholesale electricity revenues decreased $1.732 billion, or 56%, to $1.383 billion in 2009 as compared to 2008. Volatility in wholesale revenues and purchased power costs reflects movements in natural gas prices, as lower natural gas prices in 2009 drove a 46% decline in average wholesale electricity sales prices. Reported wholesale revenues and purchased power costs also reflect changes in volumes of bilateral contracting activity entered into to mitigate the effects of demand volatility and congestion. Results in 2009 reflect lower demand volatility and a decline in congestion, which drove a 10% decline in wholesale sales volumes. Net purchases of balancing electricity from ERCOT totaling $80 million in 2009 and $214 million in 2008, which were previously disclosed separately, are now included within wholesale electricity revenues.

Retail electricity revenues declined $97 million, or 2%, to $6.231 billion and reflected the following:

 

   

Lower average pricing contributed $242 million to the revenue decline. The change in average pricing reflected lower average contracted business rates driven by lower wholesale electricity prices, partially offset by higher average pricing in the residential and non-contract business markets resulting from advanced meter surcharges as well as customer mix.

 

   

Retail sales volume growth of 2% increased revenues by $145 million. Volumes rose in the business markets driven by changes in customer mix resulting from contracting activity, but declined slightly in the residential market driven by a 3% decrease in customers.

Other operating revenues decreased $88 million, or 23%, to $292 million in 2009 due to lower natural gas prices and lower volumes on sales of natural gas to industrial customers.

The change in operating revenues also reflected a $41 million decrease in amortization of intangible assets arising from purchase accounting reflecting expiration of retail sales contracts.

Fuel, purchased power costs and delivery fees decreased $1.666 billion, or 30%, to $3.934 billion in 2009. This decrease was driven by lower purchased power costs due to the effect of lower natural gas prices, decreased demand volatility and reduced congestion as discussed above regarding wholesale revenues. Lower costs of replacement power during unplanned generation unit repair outages contributed to improved margin. Other factors contributing to lower fuel and purchased power costs included lower natural gas-fueled generation and lower related fuel costs ($374 million), the effect of lower natural gas prices on natural gas purchased for sale to industrial customers ($116 million) and lower amortization of intangible assets arising from purchase accounting ($26 million).

Overall baseload generation production increased 3% in 2009 reflecting a 5% increase in nuclear production and a 2% increase in lignite/coal-fueled production. The increase in nuclear production, which reflects two refueling outages in 2008 compared to one refueling outage in 2009 and investments to increase generation capacity, resulted in improved margin. The increase in lignite/coal-fueled production reflected generation from the new units placed in service in the fourth quarter 2009, partially offset by generation reductions during certain periods when power could be purchased in the wholesale market at prices below production costs, which was largely due to lower natural gas prices and higher wind generation availability.

 

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Following is an analysis of amounts reported as net gain from commodity hedging and trading activities for the years ended December 31, 2009 and 2008, which totaled $1.736 billion and $2.184 billion, respectively:

Year Ended December 31, 2009Unrealized mark-to-market net gains totaling $1.277 billion included:

 

   

$1.260 billion in net gains related to hedge positions, which includes $1.719 billion in net gains from changes in fair value, driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $459 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

 

   

$17 million in net gains related to trading positions, which includes $22 million in net gains from changes in fair value and $5 million in net losses that represent reversals of previously recorded net gains on positions settled in the period.

Realized net gains totaling $459 million included:

 

   

$449 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

 

   

$10 million in net gains related to trading positions.

Year Ended December 31, 2008 — Unrealized mark-to-market net gains totaling $2.281 billion included:

 

   

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

 

   

$68 million in “day one” net losses related to large hedge positions (see Note 13 to Financial Statements), and

 

   

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

Realized net losses totaling $97 million included:

 

   

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

 

   

$80 million in net gains related to trading positions.

Unrealized gains and losses that are related to physically settled derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $52 million in net losses in 2009 and $48 million in net gains in 2008.

Operating costs increased $16 million, or 2%, to $693 million in 2009 driven by $28 million in costs related to the new lignite-fueled generation facilities. The change also reflected $19 million in higher maintenance costs incurred during planned and unplanned lignite-fueled generation unit outages in 2009 that was more than offset by the $31 million effect of two planned nuclear generation unit outages in 2008 as compared to one in 2009.

Depreciation and amortization increased $80 million, or 7%, to $1.172 billion in 2009. The increase was driven by $39 million in higher amortization expense related to the intangible asset representing retail customer relationships recorded in purchase accounting and $24 million due to the placement in service of two new generation units and related mining assets. Increased lignite generation unit depreciation as a result of normal capital additions as well as adjustments to useful lives of components was partially offset by lower natural gas generation unit depreciation resulting from an impairment in 2008.

 

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SG&A expenses increased $61 million, or 9%, to $741 million in 2009. The increase reflected $36 million in higher retail bad debt expense, reflecting higher delinquencies due to delays in final bills and disconnects resulting from a system conversion, customer losses and general economic conditions. The increase also reflected higher employee related expenses, the implementation of a new retail customer information management system and the transition of certain previously outsourced customer operations, partially offset by $13 million in lower fees associated with the sale of receivables program.

See Note 2 to Financial Statements for discussion of the impairments of goodwill of $70 million in 2009 and $8.0 billion in 2008.

Other income totaled $59 million in 2009 and $35 million in 2008. The 2009 amount included a $23 million reversal of a use tax accrual, an $11 million reversal of exit liabilities recorded in connection with the termination of outsourcing arrangements (see Note 15 to Financial Statements), a $6 million fee received related to an interest rate swap/commodity hedge derivative agreement, $5 million in royalty income and $5 million in sales/use tax refunds. The 2008 amount included an insurance recovery of $21 million and $4 million in royalty income. See Note 6 to Financial Statements for more details.

Other deductions totaled $63 million in 2009 and $1.263 billion in 2008. The 2009 amount included $34 million in charges for the impairment of land expected to be sold within the next 12 months, $7 million in charges for severance and other individually immaterial miscellaneous expenses. The 2008 amount included $501 million in impairment charges related to NOx and SO2 environmental allowances intangible assets and $481 million related to trade name intangible assets, both discussed in Note 2 to Financial Statements, $229 million in impairment charges related to the natural gas-fueled generation facilities discussed in Note 3 to 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 filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 6 to Financial Statements for more details.

Interest expense and related charges decreased $2.066 billion, or 49%, to $2.121 billion in 2009. The decrease reflected a $696 million unrealized mark-to-market net gain related to interest rate swaps in 2009 compared to a $1.477 billion net loss in 2008, partially offset by $117 million in increased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges in August 2008.

Income tax expense totaled $351 million in 2009 compared to an income tax benefit totaling $504 million in 2008. Excluding the impacts of the goodwill impairment of $70 million in 2009 and $8.0 billion in 2008, the effective income tax rate was 37.5% in 2009 and 32.7% in 2008. (These nondeductible charges distort the comparison; therefore, they have been excluded for purposes of a more meaningful discussion.) The increase in the rate reflects the effect of interest accrued for uncertain tax positions, which increased the rate on income in 2009 and decreased the rate on a loss in 2008.

After-tax results improved $9.554 billion to net income of $515 million in 2009, reflecting the 2008 impairment of goodwill, the 2008 impairment charges reported in other deductions and the change in unrealized mark-to-market values of interest rate swaps reported in interest expense, partially offset by lower net gains from commodity hedging and trading activities driven by lower unrealized mark-to-market net gains.

 

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

The table below summarizes the changes in commodity contract assets and liabilities for the periods presented. The net changes in these assets and liabilities, excluding “other activity” as described below, represent the pretax effect on earnings of positions in the commodity contract portfolio that are marked-to-market in net income (see Note 13 to Financial Statements). The portfolio consists primarily of economic hedges but also includes trading positions.

 

     Year Ended December 31,  
     2010     2009     2008  

Commodity contract net asset (liability) as of beginning of period

   $ 1,718      $ 430      $ (1,917

Settlements of positions (a)

     (943     (518     39   

Changes in fair value (b)

     2,162        1,741        2,294   

Other activity (c)

     160        65        14   
                        

Commodity contract net asset as of end of period

   $ 3,097      $ 1,718      $ 430   
                        

 

(a) Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and losses recognized in the settlement period).
(b) Represents unrealized gains and losses recognized, primarily related to positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”). Includes gains and losses recorded at contract inception dates (see Note 13 to the Financial Statements).
(c) The 2010 amount includes a $116 million noncash gain on termination of a long-term power sales contract. Includes amounts related to options purchased and sold and physical natural gas exchange transactions.

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

 

     Year Ended December 31,  
     2010      2009      2008  

Unrealized gains (losses) related to contracts marked-to-market

   $ 1,219       $ 1,223       $ 2,333   

Ineffectiveness gains (losses) related to cash flow hedges

     2         2         (4
                          

Total unrealized gains (losses) related to commodity contracts

   $ 1,221       $ 1,225       $ 2,329   
                          

 

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Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of December 31, 2010, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

 

     Maturity dates of unrealized commodity contract asset as of  December 31, 2010  

Source of fair value

   Less than
1 year
    1-3 years     4-5 years     Excess of
5 years
    Total  

Prices actively quoted

   $ (139   $ (9   $ —        $ —        $ (148

Prices provided by other external sources

     1,248        1,655        —          —          2,903   

Prices based on models

     (7     (21     370        —          342   
                                        

Total

   $ 1,102      $ 1,625      $ 370      $ —        $ 3,097   
                                        

Percentage of total fair value

     36     52     12     —       100

The “prices actively quoted” category reflects only exchange traded contracts for which active quotes are readily available. The “prices provided by other external sources” category represents forward commodity positions valued using prices for which over-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT that are deemed active markets (excluding the West hub) generally extend through 2013 and over-the-counter quotes for natural gas generally extend through 2015, depending upon delivery point. The “prices based on models” category contains the value of all nonexchange traded options, valued using option pricing models. In addition, this category contains other contractual arrangements that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 11 to Financial Statements for fair value disclosures and discussion of fair value measurements.

 

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COMPREHENSIVE INCOME

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

 

     Year Ended December 31,  
     2010      2009     2008  

Net decrease in fair value of cash flow hedges:

       

Commodities

   $ —         $ (20   $ (8

Financing – interest rate swaps

     —           —          (173
                         
     —           (20     (181
                         

Derivative value net losses reported in net income that relate to hedged transactions recognized in the period:

       

Commodities

     1         11        11   

Financing – interest rate swaps

     58         118        111   
                         
     59         129        122   
                         

Total income (loss) effect of cash flow hedges reported in other comprehensive income

   $ 59       $ 109      $ (59
                         

EFCH 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, but as of December 31, 2010 and 2009, there were no such instruments accounted for as cash flow or fair value hedges. Amounts in accumulated other comprehensive income include the value of dedesignated and terminated cash flow hedges at the time of such dedesignation/termination, less amounts reclassified to earnings as the original hedged transactions are recognized, unless the hedged transactions become probable of not occurring. The effects of the hedge will be recorded in the statement of income as the hedged transactions are actually settled and affect earnings. Also see Note 13 to Financial Statements.

 

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FINANCIAL CONDITION

Liquidity and Capital Resources

Operating Cash Flows

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 — Cash provided by operating activities decreased $127 million to $1.257 billion in 2010. The decrease reflected a $350 million effect of the amended accounting standard related to the accounts receivable securitization program (see Note 7 to Financial Statements), under which the $383 million of funding under the program as of the January 1, 2010 adoption is reported as a use of operating cash flows and a source of financing cash flows, with subsequent 2010 activity reported as financing, and the $33 million decline in funding in 2009 is reported as use of operating cash flows. The change in cash provided by operating activities also reflected improved working capital performance, particularly in retail accounts receivable due to the effects in 2009 of the implementation of a new customer information management system and more timely collections in 2010, as well as higher cash earnings driven by the contribution of the new generation units. These benefits were partially offset by an increase in cash interest payments net of capitalized interest and a decline in cash received as margin deposits.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 — Cash provided by operating activities totaled $1.384 billion and $1.657 billion in 2009 and 2008, respectively. The $273 million decrease reflected:

 

   

a $347 million unfavorable change in net margin deposits received primarily due to the effects of forward natural gas prices on positions in the long-term hedging program and

 

   

a $267 million increase in income taxes paid,

partially offset by

 

   

a $253 million decrease in cash interest paid driven by the payment of approximately $202 million of interest with new notes instead of cash as discussed under “Toggle Notes Interest Election” below.

Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $329 million, $409 million and $457 million for the years ended December 31, 2010, 2009 and 2008, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent with industry practice, and amortization of intangible net assets and debt fair value discounts arising from purchase accounting that is reported in various other income statement line items including operating revenues, fuel and purchased power costs and delivery fees, other income and interest expense and related charges.

Financing Cash Flows

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 — Cash provided by financing activities totaled $27 million in 2010 compared to $279 million in 2009. The $252 million change was driven primarily by debt repurchases under EFCH’s liability management program and repayments of debt at maturity, partially offset by the effect of the amended accounting standard related to the accounts receivable securitization program (see Note 7 to Financial Statements), under which the $96 million of funding under the program in 2010 is reported as financing cash flows.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 — Cash provided by financing activities totaled $279 million and $1.289 billion in 2009 and 2008, respectively. The $1.010 billion decrease reflected reduced borrowings under the TCEH Senior Secured Facilities driven by the decrease in expenditures related to the construction of new generation facilities which were nearing completion.

See Note 8 to Financial Statements for further detail of short-term borrowings and long-term debt.

 

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Investing Cash Flows

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 — Cash used in investing activities totaled $1.338 billion and $2.048 billion in 2010 and 2009, respectively. Capital expenditures (excluding nuclear fuel purchases) totaled $796 million and $1.324 billion in 2010 and 2009, respectively. The $528 million decline in capital spending reflected a decrease in spending related to the construction of the now complete new generation facilities. The change in investing activities also reflects lower amounts loaned (in the form of a demand note) to EFH Corp.

Capital expenditures in 2010 consisted of:

 

   

$487 million for major maintenance, primarily in existing generation operations;

 

   

$140 million related to completion of the construction of a second generation unit and mine development at Oak Grove;

 

   

$106 million for environmental expenditures related to existing generation units, and

 

   

$42 million for information technology and other corporate investments;

 

   

$34 million related to nuclear generation development, and

 

   

$29 million primarily related to the new retail customer information system.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 — Cash used in investing activities totaled $2.048 billion and $2.682 billion in 2009 and 2008, respectively, including capital expenditures totaling $1.324 billion and $1.908 billion, respectively. The decline in capital spending primarily reflected a decrease in spending related to the construction of the new generation facilities. The decrease in capital spending was partially offset by increased amounts loaned (in the form of a demand note) to EFH Corp.

Debt Financing Activity Activities related to short-term borrowings and long-term debt during the year ended December 31, 2010 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):

 

     Borrowings (a)      Repayments
and
Repurchases (b)
 

TCEH

   $ 1,786       $ 2,565   

EFCH

     —           9   

EFH Corp (pushed down to EFCH)

     425         1,946   
                 

Total long-term

     2,211         4,520   
                 

Total short-term – TCEH (c)

     172         —     
                 

Total

   $ 2,383       $ 4,520   
                 

 

(a) Includes the following activities:

 

   

$350 million of TCEH 15% Notes issued by TCEH, the net proceeds from which were used to repurchase TCEH Senior Notes;

 

   

Principal increases in payment of accrued interest totaling $212 million of TCEH Toggle Notes;

 

   

$1.221 billion of TCEH 15% Notes issued by TCEH in debt exchanges;

 

   

$656 million of EFH Corp. 10% Notes issued by EFH Corp. in debt exchanges or for cash used to repurchase Merger-related debt (50% pushed down to EFCH), and

 

   

Principal increases in payment of accrued interest totaling $194 million of EFH Corp. Toggle Notes (50% pushed down to EFCH).

 

(b) Includes $3.873 billion of noncash retirements (including discounts captured on cash repurchases) as a result of 2010 debt repurchase and exchange transactions.
(c) Short-term amounts represent net borrowings/repayments.

See Note 8 to Financial Statements for further detail of long-term debt and other financing arrangements.

 

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EFCH regularly monitors the capital and bank credit markets for liability management opportunities that EFCH believes will improve its balance sheet, including capturing debt discount and extending debt maturities. As a result, EFCH may engage, from time to time, in liability management transactions. Future activities under the liability management program may include the purchase of EFCH’s outstanding debt for cash in open market purchases or privately negotiated transactions (including pursuant to a Section 10b-5(1) plan) or via public or private exchange or tender offers. Moreover, as part of the liability management program, EFCH may refinance its existing debt, including the TCEH Senior Secured Credit Facilities.

In evaluating whether to undertake any liability management transaction, including any refinancing, EFCH will take into account liquidity requirements, prospects for future access to capital, contractual restrictions, the market price of its outstanding debt and other factors. Any liability management transaction, including any refinancing, may occur on a stand-alone basis or in connection with, or immediately following, other liability management transactions.

Available Liquidity The following table summarizes changes in available liquidity for the year ended December 31, 2010.

 

     Available Liquidity  
     December 31, 2010      December 31, 2009      Change  

Cash and cash equivalents

   $ 47       $ 94       $ (47

TCEH Revolving Credit Facility (a)

     1,440         1,721         (281

TCEH Letter of Credit Facility

     261         399         (138
                          

Subtotal

   $ 1,748       $ 2,214       $ (466

Short-term investment (b)

     —           65         (65
                          

Total liquidity (c)

   $ 1,748       $ 2,279       $ (531
                          

 

(a) As of December 31, 2010 and 2009, the TCEH Revolving Credit Facility includes $94 million and $141 million, respectively, of commitments from the Lehman that are only available from the fronting banks and the swingline lender.
(b) December 31, 2009 amount includes $65 million in letters of credit posted related to certain interest rate swaps transactions. Pursuant to the related agreement, the collateral was returned in March 2010. See Note 13 to Financial Statements.
(c) As of December 31, 2010 and 2009, total liquidity includes $465 million and $333 million, respectively, of net receipts of margin deposits from counterparties related to commodity positions (net of $166 million and $187 million, respectively, posted with counterparties).

Note: Available liquidity in the future could benefit from additional exercises of the payment-in-kind (PIK) option on the TCEH Toggle Notes, which for the remaining payment dates from May 2011 through November 2012 would avoid cash interest payments of approximately $295 million.

See Note 8 to Financial Statements for additional discussion of the credit facilities.

The $531 million decrease in liquidity reflected the increase in amounts loaned to EFH Corp. and an increase in letters of credit posted as collateral support with ERCOT in conjunction with ERCOT’s transition to a nodal wholesale market structure.

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

 

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TCEH made its 2010 and 2009 interest payments and will make its May 2011 interest payment on the TCEH Toggle Notes by using the PIK feature of those notes. During the applicable interest periods, the interest rate on the notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the notes by approximately $212 million in 2010, including $7 million principal amount paid to EFH Corp. and $202.5 million in 2009, and is expected to further increase the aggregate principal amount of the notes by $79 million in May 2011. The elections increased liquidity in 2010 by an amount equal to $198 million and is expected to further increase liquidity in May 2011 by an amount equal to an estimated $74 million, constituting the amounts of cash interest that otherwise would have been payable on the notes.

Similarly, EFH Corp. made its 2010 and 2009 interest payments and will make its May 2011 interest payment on the EFH Corp. Toggle Notes by using the PIK feature of those notes. During such applicable interest periods, the interest rate on these notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the notes by $194 million in 2010 (excluding $130 million principal amount issued to EFIH as holder of $2.166 billion principal amount of EFH Corp. Toggle Notes acquired in the debt exchange completed in August 2010) and $309 million in 2009 and is expected to further increase the aggregate principal amount of the notes by $34 million in May 2011 (excluding $138 million principal amount expected to be issued to EFIH). The elections increased liquidity in 2010 by an amount equal to approximately $182 million (excluding $122 million related to notes held by EFIH) and is expect to further increase liquidity in May 2011 by an amount equal to a currently estimated $32 million, (excluding $129 million related to notes held by EFIH), constituting the amounts of cash interest that otherwise would have been payable on the notes.

Liquidity Effects of Commodity Hedging and Trading Activities — Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other forms of credit support to satisfy such collateral obligations. In addition, TCEH’s Commodity Collateral Posting Facility (CCP facility), an uncapped senior secured revolving credit facility that matures in December 2012, funds the cash collateral posting requirements for a significant portion of the positions in the long-term hedging program not otherwise secured by a first-lien in the assets of TCEH. The aggregate principal amount of the CCP facility is determined by the exposure arising from higher forward market prices, regardless of the amount of such exposure, on a portfolio of certain natural gas hedging transaction volumes. Including those hedging transactions where margin deposits are covered by unlimited borrowings under the CCP facility, as of December 31, 2010, more than 95% of the long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral requirements for those hedging transactions. Due to declines in forward natural gas prices, no amounts were borrowed against the CCP facility at December 31, 2010 and 2009. See Note 8 to Financial Statements for more information about the TCEH Senior Secured Facilities, which includes the CCP facility.

As of December 31, 2010, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

 

   

$165 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $183 million posted as of December 31, 2009;

 

   

$630 million in cash has been received from counterparties, net of $1 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $516 million received, net of $4 million in cash posted, as of December 31, 2009;

 

   

$473 million in letters of credit have been posted with counterparties, as compared to $379 million posted as of December 31, 2009, and

 

   

$25 million in letters of credit have been received from counterparties, as compared to $44 million received as of December 31, 2009.

 

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With respect to exchange cleared transactions, these transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variance margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. With respect to cash collateral that is received, such cash collateral is either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or it is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing liquidity in the event that it was not restricted. As of December 31, 2010, restricted cash collateral held totaled $33 million. See Note 20 to Financial Statements regarding restricted cash.

With the long-term hedging program, increases in natural gas prices generally result in increased cash collateral and letter of credit postings to counterparties. As of December 31, 2010, approximately 300 million MMBtu of positions related to the long-term hedging program were not directly secured on an asset-lien basis and thus have cash collateral posting requirements. The uncapped CCP facility supports the collateral posting requirements related to most of these transactions.

Interest Rate Swap Transactions See Note 8 to Financial Statements for TCEH interest rate swaps entered into as of December 31, 2010.

Income Tax Refunds/Payments Income tax payments related to the Texas margin tax are expected to total approximately $42 million, and net refunds of federal income taxes are expected to total approximately $20 million. Income tax payments totaled $49 million and $27 million in the years ended December 31, 2010 and 2009, respectively.

Accounts Receivable Securitization Program — TXU Energy participates in EFH Corp.’s accounts receivable securitization program with financial institutions (the funding entities). As discussed in Note 1 to Financial Statements, in accordance with amended transfers and servicing accounting standards, the trade accounts receivable amounts under the program are reported as pledged balances and the related funding amounts are reported as short-term borrowings. Under the program, TXU Energy (originator) sells retail trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp., which sells undivided interests in the purchased accounts receivable for cash to entities established for this purpose by the funding entities. All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $96 million and $383 million as of December 31, 2010 and 2009, respectively. See Note 7 to Financial Statements for a more complete description of the program including amendments to the program in June 2010 and a related reduction in funding, the impact of the program on the financial statements for the periods presented and the contingencies that could result in termination of the program and a reduction of liquidity should the underlying financing be settled.

Liquidity Needs, Including Capital Expenditures Capital expenditures, including capitalized interest, for 2011 are expected to total approximately $650 million and include:

 

   

$450 million for major maintenance, primarily in generation operations;

 

   

$75 million for environmental expenditures related to generation units (a), and

 

   

$125 million for nuclear fuel purchases.

 

  (a) Expenditures are classified as environmental in nature if the projects are the direct result of environmental regulations.

EFCH expects cash flows from operations combined with availability under its credit facilities discussed in Note 8 to Financial Statements to provide sufficient liquidity to fund its current obligations, projected working capital requirements and capital spending for a period that includes the next twelve months.

 

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Capitalization — EFCH’s capitalization ratios consisted of 126.4% and 115.1% long-term debt, less amounts due currently, and (26.4)% and (15.1)% common stock equity, as of December 31, 2010 and 2009, respectively. Total debt to capitalization, including short-term debt, was 124.4% and 114.5% as of December 31, 2010 and 2009, respectively.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain of EFCH’s financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of December 31, 2010, EFCH was in compliance with all such maintenance covenants.

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

Adjusted EBITDA (as used in the maintenance covenant contained in the TCEH Senior Secured Facilities) for the year ended December 31, 2010 totaled $3.850 billion for TCEH. See Exhibit 99(b) and 99(c) for a reconciliation of net income to Adjusted EBITDA for TCEH and EFH Corp., respectively, for the years ended December 31, 2010 and 2009.

The table below summarizes TCEH’s secured debt to Adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp. and TCEH that are applicable under certain other threshold covenants in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the TCEH Senior Secured Second Lien Notes (for 2010), the EFH Corp. Senior Notes, and the EFH Corp. Senior Secured Notes as of December 31, 2010 and 2009. The debt incurrence and restricted payments/limitations on investments covenants thresholds described below represent levels that must be met in order for EFH Corp. or TCEH to incur certain permitted debt or make certain restricted payments and/or investments. EFCH and its consolidated subsidiaries are in compliance with their maintenance covenants.

 

    December 31,
2010
  December 31,
2009
  Threshold Level as of
December 31, 2010

Maintenance Covenant:

     

TCEH Senior Secured Facilities:

     

Secured debt to Adjusted EBITDA ratio (a)

  5.19 to 1.00   4.76 to 1.00   Must not exceed 6.75 to 1.00 (b)

Debt Incurrence Covenants:

     

EFH Corp. Senior Secured Notes:

     

EFH Corp. fixed charge coverage ratio

  1.3 to 1.0   1.2 to 1.0   At least 2.0 to 1.0

TCEH fixed charge coverage ratio

  1.5 to 1.0   1.5 to 1.0   At least 2.0 to 1.0

TCEH Senior Notes and TCEH Senior Secured Second

     

Lien Notes:

     

TCEH fixed charge coverage ratio

  1.5 to 1.0   1.5 to 1.0   At least 2.0 to 1.0

TCEH Senior Secured Facilities:

     

TCEH fixed charge coverage ratio

  1.5 to 1.0   1.5 to 1.0   At least 2.0 to 1.0

Restricted Payments/Limitations on Investments Covenants:

     

EFH Corp. Senior Notes:

     

General restrictions (Sponsor Group payments):

     

EFH Corp. leverage ratio

  8.5 to 1.0   9.4 to 1.0   Equal to or less than 7.0 to 1.0

EFH Corp. Senior Secured Notes:

     

General restrictions (non-Sponsor Group payments):

     

EFH Corp. fixed charge coverage ratio (c)

  1.6 to 1.0   1.4 to 1.0   At least 2.0 to 1.0

General restrictions (Sponsor Group payments):

     

EFH Corp. fixed charge coverage ratio (c)

  1.3 to 1.0   1.2 to 1.0   At least 2.0 to 1.0

EFH Corp. leverage ratio

  8.5 to 1.0   9.4 to 1.0   Equal to or less than 7.0 to 1.0

TCEH Senior Notes and TCEH Senior Secured Second

     

Lien Notes:

     

TCEH fixed charge coverage ratio

  1.5 to 1.0   1.5 to 1.0   At least 2.0 to 1.0

TCEH Senior Secured Facilities:

     

Payments to Sponsor Group:

     

TCEH total debt to Adjusted EBITDA ratio

  7.9 to 1.0   8.4 to 1.0   Equal to or less than 6.5 to 1.0

 

 

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(a) In accordance with the terms of the TCEH Senior Secured Facilities and as the result of the new Sandow and first Oak Grove generating units achieving average capacity factors of greater than or equal to 70% for the three months ended March 31, 2010, the maintenance covenant as of December 31, 2010 includes Adjusted EBITDA for the units and the proportional amount of outstanding debt under the Delayed Draw Term Loan (see Note 8 to Financial Statements) applicable to the two units.
(b) Threshold level will decrease to a maximum of 6.50 to 1.00 effective December 31, 2011. Calculation excludes secured debt that ranks junior to the TCEH Senior Secured Facilities.
(c) The EFH Corp. fixed charge coverage ratio for non-Sponsor Group payments includes the results of Oncor Holdings and its subsidiaries. The EFH Corp. fixed charge coverage ratio for Sponsor Group payments excludes the results of Oncor Holdings and its subsidiaries.

Material Credit Rating Covenants and Credit Worthiness Effects on Liquidity — As a result of TCEH’s non-investment grade credit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, as of December 31, 2010, counterparties to those contracts could have required TCEH to post up to an aggregate of $17 million in additional collateral. This amount largely represents the below market terms of these contracts as of December 31, 2010; thus, this amount will vary depending on the value of these contracts on any given day.

Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. As of December 31, 2010, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $28 million, with $14 million of this amount posted for the benefit of Oncor.

The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of December 31, 2010, TCEH posted letters of credit in the amount of $73 million, which are subject to adjustments.

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

ERCOT has rules in place to assure adequate credit worthiness of parties that participate in the “day-ahead” and “real-time markets” operated by ERCOT. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $240 million as of December 31, 2010 (which is subject to weekly adjustments based on settlement activity with ERCOT). This amount includes an increase of approximately $200 million in letters of credit in the fourth quarter 2010 driven by the December 2010 implementation of the nodal wholesale market.

Other arrangements of EFCH and its subsidiaries, including the accounts receivable securitization program (see Note 7 to Financial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the relevant credit ratings.

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

Material Cross Default Provisions — Certain financing arrangements contain provisions that may result in an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenants that could or does result in an acceleration of payments due. Such provisions are referred to as “cross default” provisions.

A default by TCEH or any of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to the accounts receivable securitization program, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity of outstanding balances ($22.304 billion as of December 31, 2010) under such facilities.

 

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

Under the terms of a TCEH rail car lease, which had $45 million in remaining lease payments as of December 31, 2010 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

Under the terms of another TCEH rail car lease, which had $50 million in remaining lease payments as of December 31, 2010 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

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

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

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

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

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

 

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Long-Term Contractual Obligations and Commitments The following table summarizes EFCH’s contractual cash obligations as of December 31, 2010 (see Notes 8 and 9 to Financial Statements for additional disclosures regarding these long-term debt and noncancellable purchase obligations).

 

Contractual Cash Obligations

   Less Than
One Year
     One to
Three
Years
     Three to
Five
Years
     More
Than Five
Years
     Total  

Long-term debt — principal (a)

   $ 644       $ 520       $ 24,131       $ 4,905       $ 30,200   

Long-term debt — interest (b)

     2,285         4,414         2,597         2,579         11,875   

Operating and capital leases (c)

     56         112         91         272         531   

Obligations under commodity purchase and services agreements (d)

     1,316         1,276         695         1,019         4,306   
                                            

Total contractual cash obligations

   $ 4,301       $ 6,322       $ 27,514       $ 8,775       $ 46,912   
                                            

 

(a) Excludes capital lease obligations, unamortized discounts and fair value premiums and discounts related to purchase accounting. Also excludes $96 million of additional principal amount of notes expected to be issued in May 2011 and due in 2016 and 2017, reflecting the election of the PIK feature on toggle notes as discussed above under “Toggle Notes Interest Election.” More than five years period includes $850 million of EFH Corp. notes pushed down to EFCH (See Note 8 to Financial Statements.)
(b) Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interest rate swaps are calculated based on interest rates in effect as of December 31, 2010.
(c) Includes short-term noncancellable leases.
(d) Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments. Amounts presented for variable priced contracts assumed the year-end 2010 price remained in effect for all periods except where contractual price adjustment or index-based prices were specified.

The following are not included in the table above:

 

   

contracts between affiliated entities and intercompany debt;

 

   

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

 

   

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

 

   

employment contracts with management;

 

   

estimated funding of pension plan totaling $400 thousand in 2011 and approximately $102 million for the 2011 to 2015 period, and

 

   

liabilities related to uncertain tax positions totaling $931 million discussed in Note 4 to Financial Statements as the ultimate timing of payment is not known.

Guarantees — See Note 9 to Financial Statements for details of guarantees.

OFF BALANCE SHEET ARRANGEMENTS

See Notes 9 and 18 to Financial Statements regarding guarantees and VIEs.

COMMITMENTS AND CONTINGENCIES

See Note 9 to Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

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

 

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REGULATORY MATTERS

Regulatory Investigations and Reviews

See discussions in Part I under “Environmental Regulations and Related Considerations” and in Note 9 to Financial Statements.

Sunset Review

PURA, the PUCT, the RRC, ERCOT, the TCEQ and the Office of Public Utility Counsel (OPUC) will be subject to “sunset” review by the Texas Legislature in the 2011 legislative session. Sunset review includes, generally, a comprehensive review of the need for and effectiveness of an administrative agency (the PUCT, the RRC, ERCOT, the TCEQ or the OPUC), along with an evaluation of the advisability of any changes to that agency’s authorizing legislation (PURA). In 2010, the Texas Sunset Advisory Commission adopted various recommendations regarding these agencies and submitted its recommendations for the Texas Legislature’s consideration early in the session, which began in January 2011. EFCH cannot predict the outcome of the sunset review process.

 

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

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

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

Disclosures related to specific mines pursuant to Section 1503 of the recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act sourced from data documented as of January 10, 2011 and January 17, 2011 in the MSHA Data Retrieval System for the three months and year ended December 31, 2010, respectively (except pending legal actions, which are as of December 31, 2010), are as follows:

 

     Three Months Ended December 31, 2010      Year Ended December 31, 2010  

Mine (a)

   Section 104
S and S
Citations (b)
     Proposed  MSHA
Assessments

($ thousands) (c)
     Pending Legal
Action (d)
     Section 104
S and S
Citations (b)
     Proposed
MSHA
Assessments ($
thousands) (c)
     Pending Legal
Action (d)
 

Beckville

     1         —           1         8         18         1   

Big Brown

     —           —           2         4         9         2   

Kosse

     6         —           —           6         1         —     

Oak Hill

     3         11         1         7         13         1   

Sulphur Springs

     1         2         3         3         3         3   

Tatum

     —           —           1         —           —           1   

Three Oaks

     1         —           1         3         9         1   

Winfield South

     —           1         1         1         4         1   

 

(a) Excludes mines for which there were no applicable events.
(b) Includes MSHA citations for health or safety standards that could significantly and substantially contribute to a serious injury if left unabated.
(c) Total dollar value for proposed assessments received from MSHA for all citations and orders issued in the period ended December 31, 2010, including but not limited to Sections 104, 107 and 110 citations and orders that are not required to be reported.
(d) Pending actions before the FMSHRC involving a coal or other mine.

During the three months ended December 31, 2010, EFCH’s mining operations received two citations and orders under Section 104(d) (Oak Hill mine), no citations, orders or written notices under Sections 104(b), 104(e), 107(a) or 110(b)(2) of the Mine Act, and experienced no fatalities. During the year ended December 31, 2010, EFCH’s mining operations received two citations and orders under Section 104(d) (Oak Hill Mine), one order under Section 107(a) (Beckville mine), no citations, orders or written notices under Sections 104(b), 104(e) or 110(b)(2) of the Mine Act, and experienced no fatalities.

Summary

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

 

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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Risk Oversight

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

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

Commodity Price Risk

EFCH is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. The company actively manages its portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, EFCH cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices and spark spreads (differences between the market price of electricity and its cost of production).

In managing energy price risk, EFCH enters into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. EFCH continuously monitors the valuation of identified risks and adjusts positions based on current market conditions. EFCH strives to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

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

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

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

 

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

 

     Year Ended
December 31, 2010
     Year Ended
December 31, 2009
 

Month-end average Trading VaR:

   $ 3       $ 4   

Month-end high Trading VaR:

   $ 4       $ 7   

Month-end low Trading VaR:

   $ 1       $ 2   

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

 

     Year Ended
December 31, 2010
     Year Ended
December 31, 2009
 

Month-end average MtM VaR:

   $ 426       $ 1,050   

Month-end high MtM VaR:

   $ 621       $ 1,470   

Month-end low MtM VaR:

   $ 321       $ 638   

Earnings at Risk (EaR) — This measurement estimates the potential reduction of pretax earnings for the periods presented, due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities). Transactions accounted for as cash flow hedges are also included for this measurement. A 95% confidence level and a five to 60 day holding period are assumed in determining EaR.

 

     Year Ended
December 31, 2010
     Year Ended
December 31, 2009
 

Month-end average EaR:

   $ 477       $ 1,088   

Month-end high EaR:

   $ 662       $ 1,511   

Month-end low EaR:

   $ 323       $ 676   

The decreases in the risk measures (MtM VaR and EaR) above reflected fewer positions in the long-term hedging program due to settlement upon maturity, lower market volatility and lower underlying commodity prices.

 

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Interest Rate Risk

The table below provides information concerning EFCH’s financial instruments as of December 31, 2010 and 2009 that are sensitive to changes in interest rates, which include debt obligations and interest rate swaps. EFCH has entered into interest rate swaps under which it has exchanged the difference between fixed-rate and variable-rate interest amounts calculated with reference to specified notional principal amounts at dates that generally coincide with interest payments under its credit facilities. In addition, in connection with entering into certain interest rate basis swaps to further reduce fixed borrowing costs, TCEH has changed the variable interest rate terms of certain debt from three-month LIBOR to one-month LIBOR, as discussed in Note 8 to Financial Statements. The weighted average interest rate presented is based on the rate in effect at the reporting date. Capital leases and the effects of unamortized premiums and discounts and fair value hedges are excluded from the table. See Note 8 to Financial Statements for a discussion of changes in debt obligations.

 

    Expected Maturity Date        
    (millions of dollars, except percentages)  
    2011     2012     2013     2014     2015     There-
After
    2010
Total

Carrying
Amount
    2010
Total

Fair
Value
    2009
Total

Carrying
Amount
    2009
Total

Fair
Value
 

Long-term debt (including current maturities):

                   

Fixed rate debt amount (a)

  $ 439      $ 26      $ 84      $ 43      $ 3,505      $ 4,700      $ 8,797      $ 5,879      $ 10,824      $ 8,422