10-K 1 efh-20111231x10k.htm FORM 10-K EFH-2011.12.31-10K
 
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, 2011
— OR—
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-12833
Energy Future Holdings Corp.
(Exact name of registrant as specified in its charter)
__________________________________________________________________________
Texas
 
75-2669310
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
1601 Bryan Street Dallas, TX 75201-3411
 
(214) 812-4600
(Address of principal executive offices)(Zip Code)
 
(Registrant's telephone number, including area code)
__________________________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on Which Registered
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  x    No  ¨
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
As of February 20, 2012, there were 1,679,539,245 shares of common stock, no par value, outstanding of Energy Future Holdings Corp. (substantially all of which were owned by Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp.'s parent holding company, and none of which is publicly traded).
________________________________________________________________________________
DOCUMENTS INCORPORATED BY REFERENCE
None
 



TABLE OF CONTENTS
 
 
Page
 
Item 1A.
Item 1B.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.

Energy Future Holdings Corp.'s (EFH Corp.) 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 EFH 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. The information on EFH Corp.'s website shall not be deemed a part of, or incorporated by reference into, this annual report on Form 10-K. Readers should not rely on or assume the accuracy of any representation or warranty in any agreement that EFH Corp. has filed as an exhibit to this annual report on 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, including the date of this annual report on Form 10-K.
This annual report on Form 10-K and other Securities and Exchange Commission filings of EFH Corp. and its subsidiaries occasionally make references to EFH Corp. (or "we," "our," "us" or "the company"), EFCH, EFIH, TCEH, TXU Energy, Luminant, Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, their respective parent company's financial statements 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.


i


GLOSSARY
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
Adjusted EBITDA
Adjusted EBITDA means EBITDA adjusted to exclude noncash items, unusual items and other adjustments allowable under certain of our debt arrangements. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under US GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA in this Form 10-K (see reconciliations in Exhibits 99(b), 99(c) and 99(d)) solely because of the important role that Adjusted EBITDA plays in respect of certain covenants contained in our debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with US GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management's discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.
ancillary services
Refers to services necessary to support the transmission of energy and maintain reliable operations for the entire transmission system.
CAIR
Clean Air Interstate Rule
Capgemini
Capgemini Energy LP, a provider of business support services to EFH Corp. and its subsidiaries
CFTC
US Commodity Futures Trading Commission
CO2
carbon dioxide
CPNPC
Refers to Comanche Peak Nuclear Power Company LLC, which was formed by subsidiaries of TCEH (holding an 88% equity interest) and Mitsubishi Heavy Industries Ltd. (MHI) (holding a 12% equity interest) for the purpose of developing two new nuclear generation units and obtaining a combined operating license from the NRC for the units.
Competitive Electric segment
Refers to the EFH Corp. business segment that consists principally of TCEH.
CREZ
Competitive Renewable Energy Zone
CSAPR
Refers to the final Cross-State Air Pollution Rule issued by the EPA in July 2011.
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.
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.
EFIH Notes
Refers collectively to EFIH's and EFIH Finance's 9.75% Senior Secured Notes due October 15, 2019 (EFIH 9.75% Notes), 10.000% Senior Secured Notes due December 1, 2020 (EFIH 10% Notes) and 11% Senior Secured Second Lien Notes due October 1, 2021 (EFIH 11% Notes).
EPA
US Environmental Protection Agency
EPC
engineering, procurement and construction
ERCOT
Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas
ERISA
Employee Retirement Income Security Act of 1974, as amended

ii


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
kV
kilovolts
kWh
kilowatt-hours
LIBOR
London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market
Luminant
Refers to 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.
MATS
Refers to the Mercury and Air Toxics Standard finalized by the EPA in December 2011 and published in February 2012.
Merger
The transaction referred to in the Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp., which was completed 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.
Oncor Holdings
Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context.
Oncor Ring-Fenced Entities
Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor.
OPEB
other postretirement employee benefits
PUCT
Public Utility Commission of Texas
PURA
Texas Public Utility Regulatory Act
purchase accounting
The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or "purchase price" of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.
Regulated Delivery segment
Refers to the EFH Corp. business segment that consists of the operations of Oncor.
REP
retail electric provider

iii


RRC
Railroad Commission of Texas, which among other things, has oversight of 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 certain investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman, Sachs & Co. that have an ownership interest in Texas Holdings.
TCEH
Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of EFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy markets activities. Its major subsidiaries include Luminant and TXU Energy.
TCEH Finance
Refers to TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities.
TCEH Senior Notes
Refers collectively to TCEH's 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015, Series B (collectively, TCEH 10.25% Notes) and TCEH's 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes).
TCEH Senior Secured Facilities
Refers collectively to the TCEH Term Loan Facilities, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 10 to Financial Statements for details of these facilities.
TCEH Senior Secured Notes
Refers to TCEH's 11.5% Senior Secured Notes due October 1, 2020.
TCEH Senior Secured Second Lien Notes
Refers collectively to TCEH's 15% Senior Secured Second Lien Notes due April 1, 2021 and TCEH's 15% Senior Secured Second Lien Notes due April 1, 2021, Series B.
TCEQ
Texas Commission on Environmental Quality
Texas Holdings
Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.
Texas Holdings Group
Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities.
Texas Transmission
Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of its subsidiaries or any member of the Sponsor Group.
TRE
Refers to Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and ERCOT protocols.
TXU Energy
Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT.
US
United States of America
VIE
variable interest entity


iv


PART I
Items 1. and 2. BUSINESS AND PROPERTIES

References in this report to "we," "our," "us" and "the company" are to EFH Corp. and/or its subsidiaries, as apparent in the context. See "Glossary" for descriptions of major subsidiaries and other defined terms.

EFH Corp. Business and Strategy

We are a Dallas, Texas-based energy company with a portfolio of competitive and regulated energy businesses in Texas. EFH Corp. is a holding company conducting its operations principally through its TCEH and Oncor subsidiaries. EFCH and TCEH are wholly-owned. EFIH is wholly-owned and indirectly holds an approximately 80% equity interest in Oncor. Immediately below is an organization chart of the key subsidiaries discussed in this report.
EFCH's principal asset is its investment in TCEH. EFCH is a guarantor of a significant portion of the debt of EFH Corp. (parent entity) and TCEH.

TCEH, through its subsidiaries, is 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.

TCEH owns or leases 15,427 MW of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas-fueled generation facilities. TCEH is also the largest purchaser of wind-generated electricity in Texas and the fifth largest in the US. TCEH provides competitive electricity and related services to 1.8 million retail electricity customers in Texas.

EFIH's principal assets consist of its investment in Oncor Holdings, the principal asset of which is an 80% equity interest in Oncor, and its investment in debt securities of EFH Corp. (parent entity) and TCEH that EFIH received in exchange for debt issued by EFIH. EFIH is also a guarantor of a significant portion of EFH Corp.'s (parent entity) debt.


1


Oncor is engaged in regulated electricity transmission and distribution operations in Texas that are primarily regulated by the PUCT and, in certain instances, FERC. Oncor provides both distribution services to retail electric providers that sell electricity to consumers and transmission services to other electricity distribution companies, cooperatives, municipalities and REPs. Oncor operates the largest transmission and distribution system in Texas, delivering electricity to more than three million homes and businesses and operating more than 118,000 miles of transmission and distribution lines. A significant portion of Oncor's revenues represent fees for delivery services provided to TCEH. Revenues from TCEH represented 33% and 36% of Oncor's total revenues for the years ended December 31, 2011 and 2010, respectively.


2


EFH Corp. and Oncor have implemented certain structural and operational "ring-fencing" measures based on commitments made by Texas Holdings and Oncor to the PUCT that are intended to enhance the credit quality of Oncor. These measures serve to mitigate Oncor's and Oncor Holdings' credit exposure to the Texas Holdings Group and to reduce the risk that the assets and liabilities of Oncor or Oncor Holdings would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities. Accordingly, EFH Corp. and EFIH do not control and do not consolidate Oncor for financial reporting purposes. See Note 1 to Financial Statements for a description of the material features of these "ring-fencing" measures.

As of December 31, 2011, we had approximately 9,300 full-time employees (including approximately 3,700 at Oncor). Approximately 3,000 employees are under collective bargaining agreements (including approximately 850 at Oncor).

EFH Corp.'s Market

We operate 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 Independent System Operator (ISO) 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' main interconnected transmission grid. The ERCOT ISO 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 ISO 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 resulted in a substantial increase in the number of settlement price points for participants and established a new "day-ahead market," operated by ERCOT, in which participants can enter into forward sales and purchases of electricity. The nodal market also established 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.

Oncor, along with other owners of transmission and distribution facilities in Texas, assists the ERCOT ISO in its operations. Oncor has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated distribution service area. Oncor participates with the ERCOT ISO and other ERCOT utilities in obtaining regulatory approvals and planning, designing and constructing new transmission lines in order to remove existing constraints on the ERCOT transmission grid. The transmission lines are necessary to meet reliability needs, support renewable energy production and increase bulk power transfer capability.


3


The following data is derived from information published by ERCOT:

Installed generation capacity in the ERCOT market for the year 2011 totaled approximately 82,800 MW, including approximately 2,500 MW mothballed (idled) capacity and more than 10,000 MW of wind and other resources that may not be available coincident with system need. In August 2011, ERCOT's hourly demand peaked at a record 68,379 MW. Of ERCOT's total installed capacity, approximately 57% is natural gas-fueled generation, approximately 29% is lignite/coal and nuclear-fueled generation and approximately 14% is wind and other renewable resources. In November 2010, ERCOT changed its minimum reserve margin planning criterion to 13.75% from 12.5%. In January 2012, ERCOT projected the reserve margin for the summer peak load period to be 13.9% in 2012, 12.1% in 2013, and 7.6% in 2014. 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 and Mexico, 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.


4


Natural gas-fueled generation is the predominant electricity capacity resource (approximately 57%) in the ERCOT market and accounted for approximately 40% of the electricity produced in the ERCOT market in 2011. Because of the significant amount of natural gas-fueled capacity and the ability of such facilities to more readily increase or decrease production when compared to nuclear and lignite/coal-fueled generation, marginal demand for electricity is usually met by natural gas-fueled facilities. As a result, wholesale electricity prices in ERCOT have generally moved with natural gas prices.

EFH Corp.'s Strategies

Each of our businesses focuses its operations on key safety, reliability, economic and environmental drivers for that business, as described below:

TCEH focuses on optimizing and developing its generation fleet to safely provide reliable electricity supply in a cost-effective manner and in consideration of environmental impacts, hedging its electricity price exposure and providing high quality service and innovative energy products to retail and wholesale customers.

Oncor focuses on delivering electricity in a safe and reliable manner, minimizing service interruptions and investing in its transmission and distribution infrastructure to maintain its system, serve its growing customer base with a modernized grid and support renewable energy production.

Other elements of our strategies include:

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

Safety: Placing the safety of communities, customers and employees first;
Environmental Stewardship: Continuing to make strategic and operational improvements that lead to cleaner air, land and water;
Customer Focus: Delivering products and superior service to help customers more effectively manage their use of electricity;
Community Focus: Being an integral part of the communities in which we live, work and serve;
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.


5


Drive and support growth of the ERCOT market. We expect to pursue growth opportunities across our existing business lines, including:

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

Working with ERCOT and other market participants to develop policies and protocols that provide appropriate pricing signals that encourage the development of new generation to meet growing demand in the ERCOT market.

Profitably increasing 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.

Investing in transmission and distribution, including advanced metering systems and energy efficiency initiatives, and constructing new transmission and distribution facilities to meet the needs of the growing Texas market.

Manage exposure to wholesale electricity price volatility. We actively manage our 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.

6


The historical relationship between natural gas prices and wholesale electricity prices in the ERCOT market has provided us an opportunity to manage a portion of our exposure to variability of wholesale electricity prices through a natural gas price hedging program. Under this program, TCEH has entered into market transactions involving natural gas-related financial instruments, and as of December 31, 2011, has effectively sold forward approximately 700 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 82,000 GWh at an assumed 8.5 market heat rate) for the period January 1, 2012 through December 31, 2014 at weighted average annual hedge prices ranging from $7.19 per MMBtu to $7.80 per MMBtu.


7


These transactions, together with forward power sales, have effectively hedged an estimated 86%, 58% and 31% of the price exposure, on a natural gas equivalent basis, related to TCEH's expected generation output for 2012, 2013 and 2014, respectively (assuming an 8.5 market heat rate). These estimates reflect currently governing CAIR regulation and do not include any potential impacts of the CSAPR (discussed under "Environmental Regulations and Related Considerations"). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will largely move with prices of natural gas, which is expected to be the marginal fuel for the purpose of setting electricity prices generally 70% to 90% of the time in the ERCOT market. If this relationship changes, the cash flows targeted under the natural gas price hedging program may not be achieved. For additional discussion of the natural gas price 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 Natural Gas Price 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."

Strengthen our balance sheet through a liability management program. In 2009, we initiated a liability management program focused on improving our balance sheet, and we expect to opportunistically look for ways to reduce the amount and extend the maturity of our outstanding debt. Activities under the liability management program do not include debt issued by Oncor or its subsidiaries. The program has resulted in the capture of $2.0 billion of debt discount and the extension of approximately $23.5 billion of debt maturities to 2017-2021. Activities to date have included debt exchanges, issuances and repurchases as well as amendments to the Credit Agreement governing the TCEH Senior Secured Facilities. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events – Liability Management Program" and Note 10 to Financial Statements for additional discussion of these transactions.

We regularly monitor the capital and bank credit markets for liability management opportunities. Future activities under the liability management program may include the purchase of our outstanding debt for cash in open market purchases or privately negotiated refinancing and exchange transactions (including pursuant to a Section 10b-5(1) plan) or via public or private exchange or tender offers.

In evaluating whether to undertake any liability management transaction, including any refinancing, we will take into account liquidity requirements, prospects for future access to capital, contractual restrictions, the market price of our 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. We are committed to continue to operate in compliance with all environmental laws, rules and regulations and to reduce our impact on the environment. EFH Corp.'s Sustainable Energy Advisory Board advises us in our pursuit of technology development opportunities that reduce our impact on the environment while balancing the need to help address the energy requirements of Texas. The Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, labor unions, customers, economic development in Texas and technology/reliability standards. See "Environmental Regulations and Related Considerations" below for discussion of actions we are taking to reduce emissions from our generation facilities and our investments in energy efficiency and related initiatives.

Seasonality

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


8


Operating Segments

We have aligned and report our business activities as two operating segments: the Competitive Electric segment (consisting largely of TCEH and its subsidiaries) and the Regulated Delivery segment (consisting largely of our investment in Oncor). See Note 21 to Financial Statements for additional financial information for the segments.

Competitive Electric Segment

Key management activities, including commodity price risk management and electricity sourcing for our retail and wholesale customers, are performed on an integrated basis. This integration strategy, the execution of which is discussed below in describing the activities of our wholesale operations, is a key consideration in our operating segment determination. For purposes of operational accountability and market identity, the segment operations have been grouped into Luminant, which is engaged in electricity generation and wholesale markets activities, and TXU Energy, which is engaged in retail electricity sales activities. These activities are conducted through separate legal entities.

Luminant — Luminant's existing electricity generation fleet consists of 14 plants in Texas with total installed nameplate generating capacity as shown in the table below:
Fuel Type
Installed Nameplate Capacity (MW)
 
Number of
Plant Sites
 
Number of
Units (a)
Nuclear
2,300

 
1

 
2

Lignite/coal
8,017

 
5

 
12

Natural gas (b)
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.

The generation units are located primarily on owned land. Nuclear and lignite/coal-fueled units are generally scheduled to run at capacity except for periods of scheduled maintenance activities; however, we reduce production from certain lignite/coal-fueled generation units during periods when wholesale electricity market prices are less than the unit's production costs (i.e., economic backdown). The natural gas-fueled generation units supplement the nuclear and lignite/coal-fueled generation capacity in meeting consumption in peak demand periods as production from a certain number of these units can more readily be ramped up or down as demand warrants.

Nuclear Generation Operations — Luminant operates two nuclear generation units at the Comanche Peak plant site, each of which is designed for a capacity of 1,150 MW. Comanche Peak's Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, and are generally operated at full capacity to meet the load requirements in ERCOT. Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, the refueling cycle results in the refueling of both units during the same year, which last occurred in 2011. 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 22 to 25 days. The Comanche Peak facility operated at a capacity factor of 95.7% in 2011 and 100% in both 2010 and 2009.

Luminant has contracts in place for all of its uranium and nuclear fuel conversion, enrichment and fabrication services for 2012. For the period of 2013 through 2018, Luminant has contracts in place for the acquisition of approximately 75% of its uranium requirements and 56% 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.


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The nuclear industry is developing ways to store used nuclear fuel on site at nuclear generation facilities, primarily through the use of dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation in the US. Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear fuel storage capability is sufficient for the foreseeable future.

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, 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 Texas law, is funded from Oncor's customers through an ongoing delivery surcharge. (See Note 17 to Financial Statements for discussion of the decommissioning trust fund.)

Nuclear insurance provisions are discussed in Note 11 to Financial Statements.

Nuclear Generation Development In September 2008, a subsidiary of TCEH filed a combined operating license application with the NRC for two new nuclear generation units, each with approximately 1,700 MW (gross capacity), at its existing Comanche Peak nuclear plant 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 December 2011, the NRC updated its official review schedule for the license application. Based on the schedule, the NRC expects to complete its review by July 2014, and it is expected that a license would be issued by year-end 2014.

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 and consists of the Big Brown (2 units), Monticello (3 units), Martin Lake (3 units), Oak Grove (2 units) and Sandow (2 units) plant sites. Maintenance outages at these units are scheduled during seasonal off-peak demand periods. Over the last three years, the total annual scheduled and unscheduled outages per unit (excluding three recently constructed units) averaged 31 days. Luminant's lignite/coal-fueled generation fleet operated at a capacity factor of 83.5% in 2011, 82.2% in 2010 and 86.5% in 2009, which represents top decile performance of US coal-fueled generation facilities. This performance reflects increased economic backdown of the units as described above.

In 2009 and 2010, Luminant 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.

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.

Approximately 64% of the fuel used at Luminant's lignite/coal-fueled generation units in 2011 was supplied from surface-minable lignite reserves dedicated to the Big Brown, Monticello, Martin Lake and Oak Grove plant sites, which are located adjacent to the reserves. Luminant owns or has under lease an estimated 790 million tons of lignite reserves dedicated to these sites, and has an undivided interest in 240 million tons of lignite reserves that provide fuel for the Sandow facility. Luminant also owns or has under lease approximately 85 million tons of reserves not currently dedicated to specific generation plants. In 2011, Luminant recovered approximately 32 million tons of lignite to fuel its generation plants. Luminant utilizes owned and/or leased equipment to remove the overburden and recover the lignite.


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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 2011, Luminant reclaimed more than 2,700 acres of land. In addition, Luminant planted 1.4 million trees in 2011, the majority of which were part of the reclamation effort.

Luminant meets its fuel requirements at Big Brown, Monticello and Martin Lake by blending lignite 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 planned usage, Luminant believes that it has sufficient lignite reserves for the foreseeable future and has contracted the majority of its western coal resources and all of the related transportation through 2014.

See "Environmental Regulations and Related Considerations - Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions" for discussion of potential effects of recent EPA rules on future operations of our generation units.

Natural Gas-Fueled Generation Operations — Luminant's fleet of 26 natural gas-fueled generation units totaling 5,110 MW of capacity includes 3,455 MW of currently available capacity 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. In 2010 and 2009, Luminant retired 19 natural gas-fueled units totaling 5,118 MW of installed nameplate capacity and mothballed 4 units totaling the 1,655 MW of capacity.

Wholesale Operations — Luminant's wholesale operations play a pivotal role in our Competitive Electric segment portfolio by optimally dispatching the generation fleet, sourcing all of TXU Energy's electricity requirements and managing commodity price risk associated with retail and wholesale electricity sales and generation fuel requirements.

Our electricity price exposure is managed across the complementary generation, wholesale and retail operations 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-related services to meet their demands and the operating requirements of ERCOT. In consideration of electricity generation resource availability and consumer demand levels that can be highly variable, as well as opportunities to meet longer-term objectives of larger 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, uranium and fuel oil, as well as fuel transportation costs, 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 significant part of these hedging activities is a natural gas price hedging program, described above under "EFH Corp.'s Strategies", designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, principally utilizing natural gas-related financial instruments.

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 optimizes 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.


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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 1.8 million residential and commercial retail electricity customers in Texas. Approximately 64% of retail revenues in 2011 represented sales to 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 competitively markets its services to add new customers and retain its existing customer base. There are more than 100 active REPs certified to compete within the State of Texas. Based upon data published by the PUCT, as of September 30, 2011, approximately 56% of residential customers and 66% of small commercial 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 continually improve customer satisfaction. TXU Energy offers a wide range of residential products to meet varying customer needs and is investing $100 million in energy efficiency initiatives over a five-year period ending in 2012 as part of a program to offer customers a broad set of innovative energy products and services.

Regulation — Luminant is an exempt wholesale generator under the Energy Policy Act of 2005 and is subject to the jurisdiction of the NRC with respect to its nuclear generation units. 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. In addition, Luminant is subject to the jurisdiction of the RRC's oversight of its lignite mining and reclamation operations.

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.


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Regulated Delivery Segment

The Regulated Delivery segment consists largely of our investment in Oncor. Oncor is a regulated electricity transmission and distribution company that provides the service of delivering electricity safely, reliably and economically to end-use consumers through its distribution systems, as well as providing transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas. Oncor's service territory comprises 91 counties and over 400 incorporated municipalities, including Dallas/Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler and Killeen. Oncor's transmission and distribution assets are located principally in the north-central, eastern and western parts of Texas. Most of Oncor's power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way as permitted by law. Oncor's transmission and distribution rates are regulated by the PUCT.

Oncor is not a seller of electricity, nor does it purchase electricity for resale. It provides transmission services to other electricity distribution companies, cooperatives and municipalities. It provides distribution services to REPs, which sell electricity to residential, business and other consumers. Oncor 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.

Performance — Oncor achieved or exceeded market performance protocols in 12 out of 14 PUCT market metrics in 2011. These metrics measure the success of transmission and distribution companies in facilitating customer transactions in the competitive Texas electricity market.

Investing in Infrastructure and Technology — In 2011, Oncor invested $1.4 billion in its network to construct, rebuild and upgrade transmission lines and associated facilities, to extend the distribution infrastructure, and to pursue certain initiatives in infrastructure maintenance and information technology. Reflecting its commitment to infrastructure, in September 2008, Oncor and several other ERCOT utilities filed with the PUCT a plan to participate in the construction of transmission improvements designed to interconnect existing and future renewable energy facilities to transmit electricity from Competitive Renewable Energy Zones (CREZs) identified by the PUCT. In 2009, the PUCT awarded CREZ construction projects to Oncor, and Oncor currently estimates the costs of the projects to be approximately $2.0 billion. The projects involve the construction of transmission lines to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of the state. Through 2011, Oncor's cumulative CREZ-related capital expenditures totaled $899 million, including $583 million invested in 2011. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Regulatory Matters – Oncor Matters with the PUCT."

Oncor's technology upgrade initiatives include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs. Oncor's plans provide for the full deployment of over three million advanced meters to all residential and most non-residential retail electricity customers in Oncor's service area by the end of 2012. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits. As of December 31, 2011, Oncor has installed approximately 2,302,000 advanced digital meters, including 788,000 in 2011. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $518 million as of December 31, 2011, including $158 million invested in 2011.

In addition to the potential energy efficiencies from advanced metering, Oncor expects to spend approximately $340 million ($100 million in excess of regulatory requirements) over the five-year period ending December 31, 2012 in programs designed to improve customer electricity demand efficiencies. As of December 31, 2011, approximately $265 million had been spent by Oncor, including $75 million in 2011, and 75% of the amount in excess of regulatory requirements had been spent.

In a stipulation with several parties that was approved by the PUCT in 2007, Oncor has committed to a variety of actions, including minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. Approximately 94% of this total had been spent as of December 31, 2011. This spending does not include the CREZ facilities.


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Electricity Transmission — Oncor's electricity transmission business is responsible for the safe and reliable operations of its transmission network and substations. These responsibilities consist of the construction and maintenance of transmission facilities and substations and the monitoring, controlling and dispatching of high-voltage electricity over Oncor's transmission facilities in coordination with ERCOT.

Oncor is a member of ERCOT, and its transmission business actively assists the operations of ERCOT and market participants. Through its transmission business, Oncor participates with ERCOT and other member utilities to plan, design, construct and operate new transmission lines, with regulatory approval, necessary to maintain reliability, interconnect to merchant generation facilities, increase bulk power transfer capability and minimize limitations and constraints on the ERCOT transmission grid.

Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to an interconnection to other markets, the FERC. Network transmission revenues compensate Oncor for delivery of electricity over transmission facilities operating at 60 kV and above. Other services offered by Oncor through its transmission business include, but are not limited to: system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.

PURA allows Oncor to update its transmission rates periodically to reflect changes in invested capital. This "capital tracker" provision encourages investment in the transmission system to help ensure reliability and efficiency by allowing for timely recovery of and return on new transmission investments.

As of December 31, 2011, Oncor's transmission facilities included approximately 5,407 circuit miles of 345-kV transmission lines and approximately 9,935 circuit miles of 138-and 69-kV transmission lines. Sixty-one generation facilities totaling 33,380 MW were directly connected to Oncor's transmission system as of December 31, 2011, and 288 transmission stations and 707 distribution substations were served from Oncor's transmission system.

As of December 31, 2011, Oncor's transmission facilities have the following connections to other transmission grids in Texas:
 
Number of Interconnected Lines
Grid Connections
345kV
 
138kV
 
69kV
Centerpoint Energy Inc.
8

 

 

American Electric Power Company, Inc (a)
4

 
7

 
11

Lower Colorado River Authority
8

 
22

 
3

Texas Municipal Power Agency
6

 
6

 

Texas New Mexico Power
4

 
9

 
11

Brazos Electric Power Cooperative, Inc.
6

 
109

 
22

Electric Transmission Texas, LLC
2

 
1

 

Rayburn Country Electric Cooperative, Inc.

 
37

 
6

City of Georgetown

 
2

 

Tex-La Electric Cooperative of Texas, Inc.

 
12

 
1

Other small systems operating wholly within Texas

 
4

 
2

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

Electricity Distribution Oncor's electricity distribution business is responsible for the overall safe and efficient operation of distribution facilities, including electricity delivery, power quality and system reliability. These responsibilities consist of the ownership, management, construction, maintenance and operation of the distribution system within Oncor's certificated service area. Oncor's distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through approximately 3,147 distribution feeders.

The Oncor distribution system includes over 3.2 million points of delivery. Over the past five years, the number of distribution system points of delivery served by Oncor, excluding lighting sites, grew an average of approximately 1.12% per year. Oncor added approximately 34,000 points of delivery in 2011.


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The Oncor distribution system consists of approximately 56,466 miles of overhead primary conductors, approximately 21,529 miles of overhead secondary and street light conductors, approximately 15,703 miles of underground primary conductors and approximately 9,738 miles of underground secondary and street light conductors. The majority of the distribution system operates at 25-kV and 12.5-kV.

Oncor's distribution rates for residential and small commercial users are based on actual monthly consumption (kWh), and rates for large commercial and industrial users are based on the greater of actual monthly demand (kilowatt) or 80% of peak monthly demand during the prior eleven months.

Customers Oncor's transmission customers consist of municipalities, electric cooperatives and other distribution companies. Oncor's distribution customers consist of more than 80 REPs, including TCEH and certain electric cooperatives in Oncor's certificated service area. Revenues from TCEH represented 33% of Oncor's total revenues for 2011. Revenues from subsidiaries of Reliant Energy, Inc., each of which is a non-affiliated REP, represented 12% of Oncor's total revenues for 2011. No other customer represented more than 10% of Oncor's total operating revenues. The consumers of the electricity delivered by Oncor are free to choose their electricity supplier from REPs who compete for their business.

Regulation and Rates As its operations are wholly within Texas, Oncor is not a public utility as defined in the Federal Power Act and, as a result, it is not subject to general regulation under this Act. However, Oncor is subject to reliability standards adopted and enforced by the TRE and the NERC, including NERC CIP standards, under the Federal Power Act.

In January 2011, Oncor filed for a rate review with the PUCT and 203 cities (PUCT Docket No. 38929) based on a test year ended June 30, 2010. In August 2011, the PUCT issued a final order in the rate review. The rate review, as approved, includes an approximate $137 million base rate increase and additional provisions to address certain expenses. Approximately $93 million of the increase became effective July 1, 2011, and the remainder became effective January 1, 2012. The rate review did not change Oncor's authorized regulatory capital structure of 60% debt to 40% equity or its authorized return on equity of 10.25%. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations – Regulatory Matters."

As directed by Senate Bill 1693, which was passed by the Texas Legislature in 2011, in September 2011, the PUCT approved the periodic rate adjustment rule, which allows utilities to file, under certain circumstances, up to four rate adjustments between rate reviews to recover distribution-related investments on an interim basis.

At the state level, PURA requires owners or operators of transmission facilities to provide open-access wholesale transmission services to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility's own use of its system. The PUCT has adopted rules implementing the state open-access requirements for utilities, including Oncor, that are subject to the PUCT's jurisdiction over transmission services.

Securitization Bonds Oncor's operations include its wholly-owned, bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC. This financing subsidiary was organized for the limited purpose of issuing certain securitization (transition) bonds in 2003 and 2004. Oncor Electric Delivery Transition Bond Company LLC issued $1.3 billion principal amount of transition bonds to recover generation-related regulatory asset stranded costs and other qualified costs under an order issued by the PUCT in 2002. At December 31, 2011, $554 million principal amount of transition bonds were outstanding, which mature in the period from 2012 to 2016. See Note 20 to Financial Statements for discussion of agreements between TCEH and Oncor regarding payment of interest and incremental taxes related to these bonds.

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Environmental Regulations and Related Considerations

Global Climate Change

Background — There is a concern nationally and internationally about global climate change and how greenhouse gas (GHG) emissions, such as CO2, might contribute to global climate change. GHG emissions from the combustion of fossil fuels, primarily by our lignite/coal-fueled generation units, represent the substantial majority of our total GHG emissions. CO2, methane and nitrous oxide are emitted in this combustion process, with CO2 representing the largest portion of these GHG emissions. We estimate that our generation facilities produced 68 million short tons of CO2 in 2011. Other aspects of our operations result in emissions of GHGs including, among other things, coal piles at our generation plants, sulfur hexafluoride in transmission and distribution equipment, refrigerant from our chilling and cooling equipment, fossil fuel combustion in our motor vehicles and electricity usage at our facilities and headquarters. Our financial condition and/or results of operations could be materially 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 us 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 our own evaluation and working in tandem with other companies and industry trade associations, we have supported the development of an integrated package of recommendations for the federal government to address the global climate change issue through federal legislation, including GHG emissions reduction targets for total 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, we believe that such a program should be mandatory, economy-wide, consistent with expected technology development timelines and designed in a way to limit potential harm to the economy or grid reliability and protect consumers. We believe that any mechanism for allocation of GHG emission allowances should include substantial allocation of allowances to offset the cost of GHG regulation, including the cost to electricity consumers. In addition, we participate in a voluntary electric utility industry sector climate change initiative in partnership with the DOE. Our strategies are generally consistent with the "EEI Global Climate Change Points of Agreement" published by the Edison Electric Institute in January 2009 and "The Carbon Principles" announced in February 2008 by three major financial institutions. Finally, we have created a Sustainable Energy Advisory Board that advises us on technology development opportunities that reduce the effects of our operations on the environment while balancing the need to address the energy requirements of Texas. Our Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, customers, economic development in Texas and technology/reliability standards. If, despite these efforts, a substantial number of our customers or others refuse to do business with us because of our GHG emissions, it could have a material effect on our results of operations, liquidity and financial condition.

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, our costs of compliance could be material and could have a material effect on our results of operations, liquidity and financial condition.

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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 the then EPA Administrator on the issue of when the Clean Air Act's Prevention of Significant Deterioration (PSD) program would apply to newly identified pollutants such as GHGs. 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 were required to meet the new GHG standards. Second, in April 2010, the EPA adopted GHG emission standards for certain new motor vehicles. Third, in June 2010, the EPA finalized its so-called "tailoring rule" that established new thresholds of GHG emissions for the applicability of permits under the Clean Air Act for stationary sources, including our power generation facilities. The EPA's tailoring rule defines the threshold of GHG emissions for determining applicability of the Clean Air Act's 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; however, the EPA failed to meet the July 2011 proposal date and will likely release the proposal in early 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 applies to our lignite/coal-fueled generation facilities). The report submittal date was extended to September 2011, and Luminant complied with this requirement. If limitations on emissions of GHGs from existing sources are enacted, our costs of compliance could be material and could have a material effect on our results of operations, liquidity and financial condition.

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.

Litigation In June 2011, the US Supreme Court rejected claims by various states, a municipality and certain private trusts that several power generation companies' emissions of GHGs constituted a public nuisance under federal common law. In American Electric Power Co. (AEP) v. Connecticut, the Supreme Court held that the Clean Air Act and the EPA actions it authorizes displace any federal common law right to seek abatement of carbon-dioxide emissions from fossil-fueled power plants. Regarding the question whether such claims can be brought under state law, the Supreme Court noted that the issue would depend on whether the Clean Air Act preempts state law. The Supreme Court left the preemption issue open for consideration on remand.

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 had 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 May 2011, the plaintiffs in the Comer case filed a new lawsuit in the United States District Court for the Southern District of Mississippi against numerous defendants (Comer II). The Comer II complaint reasserts that the defendants' emissions of GHGs have contributed to global warming and led to severe weather consequences. The plaintiffs assert claims for public and private nuisance, trespass and negligence, and they seek to have their case certified as a class action.

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. Oral argument related to the appeal was held in the US Court of Appeals for the Ninth Circuit in November 2011.


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

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

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. In December 2011, the UNFCCC met in Durban, South Africa and agreed to develop a document with "legal force" to address climate change by 2015, with reductions effective starting in 2020. The impact, if any, of this agreement on near-term regulatory or legislative policy cannot yet be determined.

We continue 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, we are unable to predict the potential effects on our business, financial condition and/or results of operations; however, any such effects could be material. The effect will depend, in large part, on the specific requirements of the legislation or regulation and how much, if any, of the costs are included in wholesale electricity prices.

EFH Corp.'s Voluntary Energy Efficiency, Renewable Energy, and Global Climate Change Efforts — We are considering, or expect to be actively engaged in, business activities that could result in reduced GHG emissions including:

Investing in Energy Efficiency and Related Initiatives by Our Competitive Businesses — Our competitive businesses expect to invest $100 million in energy efficiency and related initiatives over a five-year period ending in 2012, 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 MyEnergy DashboardSM, an online tool showing residential customers how and when they use electricity; 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 iThermostat, a web-enabled programmable thermostat with a load control feature for cycling air conditioners during times of peak energy demand; TXU Energy PowerSmartSM, time-based electricity rates, and TXU Energy FlexPowerSM, prepaid electricity plans, that work in conjunction with advanced metering infrastructure; in-home display devices that enable residential customers to monitor whole-house energy usage and cost in real-time and project month-end bill amounts; 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 BrightenSM Greenback Energy Efficiency Rebate Program; and programs promoting distributed renewable generation to reduce peak summer demand on the grid, such as the TXU Energy SolarLeaseSM program, our distributed renewable generation surplus buyback program, and the TXU Energy Solar Academy program;

Investing in Energy Efficiency Initiatives by Oncor — In addition to the potential energy efficiencies from advanced metering, Oncor expects to spend approximately $340 million in energy efficiency initiatives over a five-year period that ends in 2012 through such efforts as traveling across the State of Texas educating consumers about the benefits of energy efficiency, advanced meters and renewable energy, and spending over $23 million in the installation of solar photovoltaic systems in customer homes and facilities that is expected to result in savings of up to 16.5 million kWh of electricity;

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Participating in the CREZ Program — Oncor has been selected by the PUCT to construct CREZ transmission facilities (currently estimated by Oncor to cost $2.0 billion) that are designed to connect existing and future renewable energy facilities to the electricity transmission system in ERCOT;

Purchasing Electricity from Renewable Sources — We expect to remain a leader in the ERCOT market in providing electricity from renewable sources by purchasing wind power. Our total wind power portfolio is currently more than 900 MW;

Promoting the Use of Solar Power — TXU Energy provides qualified customers, through its SolarLease 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 — We continue to evaluate the development and commercialization of cleaner power facility technologies; technologies that support sequestration and/or reduction of CO2; incremental renewable sources of electricity, including wind and solar power; energy storage, including advanced battery and compressed air storage, as well as related technologies that seek to lower emissions intensity. Additionally, we continue to explore 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 are 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 — As discussed under "Nuclear Generation Development" above, we have filed an application with the NRC for combined construction and operating licenses for up to 3,400 MW of new nuclear generation capacity (the lowest GHG emission source of baseload generation currently available) at our Comanche Peak nuclear generation facility. In addition, we have (i) filed a loan guarantee application with the DOE for financing of the proposed units and (ii) formed a joint venture with Mitsubishi Heavy Industries Ltd. (MHI) to further develop the units using MHI's US-Advanced Pressurized Water Reactor technology;

Offsetting GHG Emissions by Planting Trees — We are engaged in a number of tree planting programs that offset GHG emissions, resulting in the planting of over 1.4 million trees in 2011. The majority of these trees were planted as part of our mining reclamation efforts but also include TXU Energy's Urban Tree Farm program, which has planted more than 170,000 trees since its inception in 2002, and

Installation of Substantial Emissions Control Equipment — Each of our lignite/coal-fueled generation facilities is currently equipped with substantial emissions control equipment. All of our 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 our lignite/coal-fueled generation facilities will satisfy the requirements under any future EPA or TCEQ regulations. Recent EPA regulatory actions could require us to install significant additional control equipment, resulting in material costs of compliance for our generation units, including capital expenditures and higher operating costs. These costs could result in material effects on our results of operations, liquidity and financial condition.

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Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions

Cross-State Air Pollution Rule In 2005, the EPA issued a final rule (the Clean Air Interstate Rule or CAIR) intended to implement the provisions of the Clean Air Act Section 110(a)(2)(D)(i)(I) (CAA Section 110) requiring states to reduce emissions of sulfur dioxide (SO2) and nitrogen oxide (NOx) that significantly contribute to other states failing to attain or maintain compliance with the EPA's National Ambient Air Quality Standards (NAAQS) for fine particulate matter and/or ozone. In 2008, the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) invalidated CAIR, but allowed the rule to continue until the EPA issued a final replacement rule. In August 2010, the EPA issued for comment a proposed replacement rule for CAIR called the Clean Air Transport Rule (CATR), similarly intended to implement CAA Section 110. As proposed, the CATR did not include Texas in its annual SO2 or NOx programs to address alleged downwind fine particulate matter effects.

In July 2011, the EPA issued the final replacement rule for CAIR (as finally issued, the Cross-State Air Pollution Rule (CSAPR)). Unlike the CATR, the CSAPR includes Texas in its annual SO2 and NOx emissions reduction programs, as well as the seasonal NOx emissions reduction program. These programs require significant additional reductions of SO2 and NOx emissions from fossil-fueled generation units in covered states (including Texas) and institute a limited "cap and trade" system as an additional compliance tool to achieve reductions the EPA contends are necessary to implement CAA Section 110. As adopted in July 2011 and absent a judicial stay, the CSAPR would have required our fossil-fueled generation units to (i) reduce their annual SO2 and NOx emissions by approximately 137,000 tons (64 percent) and 9,200 tons (22 percent), respectively, compared to 2010 actual levels, each beginning on January 1, 2012 and (ii) reduce their seasonal NOx emissions by approximately 3,400 tons (19 percent), compared to 2010 actual levels, beginning on May 1, 2012, which is the start of the ozone season.

In September 2011, we filed a petition for review in the D.C. Circuit Court challenging the CSAPR and a motion to stay the effective date of the CSAPR, in each case as applied to Texas.

In December 2011, the D.C. Circuit Court granted our motion and all other motions for a judicial stay of the CSAPR in its entirety, including as applied to Texas. The D.C. Circuit Court's order does not invalidate the CSAPR but stays the implementation of its emissions reduction programs until a final ruling regarding the CSAPR's validity is issued by the D.C. Circuit Court. The D.C. Circuit Court's order states that the EPA is expected to continue administering the CAIR (the predecessor rule to the CSAPR) pending the court's resolution of the petitions for review. The D.C. Circuit Court ordered us and other parties challenging the CSAPR to file opening briefs on February 9, 2012 with all briefing to be completed by March 16, 2012. The D.C. Circuit Court has scheduled oral argument for April 13, 2012. We cannot predict whether we will be successful in our legal challenge to the CSAPR, or when the D.C. Circuit Court will rule on our challenge.

In February 2012, the EPA released a final rule (Final Revisions) and a direct-to-final rule (Direct Final Rule) revising certain aspects of the CSAPR, including emissions budgets for the State of Texas. The Final Revisions increase the emissions budgets for the State of Texas by 50,517 tons for the annual SO2 program and 1,375 tons for each of the annual NOx and seasonal NOx programs. The Direct Final Rule further increases (over the Final Revisions) the Texas annual NOx emissions budget by 2,731 tons and the seasonal NOx emissions budget by 1,142 tons. If the EPA receives significant adverse comments on the Direct Final Rule, it will be withdrawn and its provisions considered in a proposed rule subject to normal notice-and-comment rulemaking procedures. In total, the emissions budgets established by the Final Revisions along with the Direct Final Rule would require our fossil-fueled generation units to reduce (i) their annual SO2 and NOx emissions by approximately 120,600 tons (56 percent) and 9,000 tons (22 percent), respectively, compared to 2010 actual levels, and (ii) their seasonal NOx emissions by approximately 3,300 tons (18 percent), compared to 2010 levels. The company could comply with these emissions limits either through physical reductions or through the purchase of emissions credits from third parties, but the volume of SO2 credits that may be purchased from sources outside of Texas is subject to limitations starting in 2014, as described further below. Because the CSAPR is currently stayed by the D.C. Circuit Court, the Final Revisions and the Direct Final Rule do not impose any immediate legal or compliance requirements on Luminant, the State of Texas, or other affected parties. We cannot predict whether, when, or in what form the CSAPR, the Final Revisions, or the Direct Final Rule will take effect.


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The CSAPR establishes a "cap and trade" system as a compliance tool. The system includes three trading programs - one for annual SO2 emissions and one each for seasonal and annual NOx emissions - that allow for limited trading of allowances among sources covered by the programs. An allowance represents a ton of emissions of SO2 or NOx and sources are required to surrender to the EPA one allowance for every ton of emissions they emit in a given compliance period. The CSAPR allocates to each covered state (including Texas) a number of allowances for each of the three programs, and those allowances are then allocated among emission sources within the state. To the extent a source's emissions exceed the number of allowances it has been allocated, the source generally may buy additional allowances from other sources that it can surrender to the EPA in order to comply with the CSAPR. Sources included in the seasonal and annual NOx programs are allowed to trade allowances with any other sources in those programs. The SO2 trading program, however, divides States into Group 1 and Group 2, and permits sources to trade SO2 allowances only with other sources in the same Group. Texas is in Group 2, which is composed of seven states. We believe that there may not be sufficient liquidity in the system for the purchase of allowances to constitute a significant element of our strategy to comply with the CSAPR as originally adopted. Further, we believe that the state assurance levels contained in the CSAPR starting in 2014 (i.e., the level of emissions permitted in a state that, to the extent exceeded, must be offset with allowances on a three to one basis - one allowance for exceeding the applicable emissions limit and two allowances for exceeding the assurance level) could prevent using allowances to offset emissions above our generation fleet's pro rata portion of the Texas assurance level as a viable compliance strategy in 2014 and beyond.

In September 2011, we announced a compliance plan to satisfy the requirements of the CSAPR as issued in July 2011. Consistent with this compliance plan, we submitted a Notice of Suspension of Operations to ERCOT in October 2011 to notify ERCOT that we would suspend operations at Monticello Units 1 and 2 as of January 1, 2012 in order to comply with the emissions limitations in the CSAPR. As a result of the D.C. Circuit Court's order staying the CSAPR, we rescinded our Notice of Suspension of Operations. While the legal challenge to the CSAPR is in process, we intend to continue evaluating the CSAPR, the Final Revisions, and the Direct Final Rule, alternatives for compliance and the expected effects on our operations, liquidity and financial results.

Material capital expenditures would be required to comply with the CSAPR, as revised in February 2012, as well as with other pending and expected environmental regulations. In 2011, total capital expenditures for environmental projects totaled $142 million. Analysis is ongoing regarding expected capital expenditures relating to the CSAPR, the status of which is uncertain given the pending legal proceeding, and the final MATS rule, which was published in February 2012. We currently estimate that total capital expenditures related to the CSAPR, MATS, and other environmental regulations will be approximately $300 million in 2012. Prior to the publication of the final MATS rule, we estimated that expenditures of more than $1.5 billion before the end of the decade in environmental control equipment would be required to comply with regulatory requirements, including the CSAPR and MATS. We are currently evaluating this estimate in light of the final MATS rule, the Final Revisions and the Direct Final Rule.

Given the uncertainty regarding the CSAPR's (including the Final Revisions and the Direct Final Rule) requirements and the timing of its implementation, we are unable to predict its effects on our results of operations, liquidity or financial condition. See Note 4 to Financial Statements for discussion of impairments of emission allowances and certain mining assets, as well as accelerated depreciation of mining assets recorded in 2011 as a result of the CSAPR.

Other EPA Actions 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. We believe our generation plants meet these SO2 allowance requirements and NOx emission rates.

SO2 and NOx 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 we believe will not have a material impact on our generation facilities. The EPA has not made a final decision on this SIP submittal; however, in December 2011 the EPA proposed a limited disapproval of the SIP and a Federal Implementation Plan for Texas providing that the inclusion in the CSAPR programs meets the requirements for SO2 and NOx reductions.


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The Clean Air Act requires each state to monitor air quality for compliance with federal health standards. The EPA is required to periodically review, and if appropriate, revise all national ambient quality standards. The standards for ozone are not being achieved in several areas of Texas. The TCEQ adopted SIP rules in May 2007 to deal with eight-hour ozone standards, which required NOx emission reductions from certain of our peaking natural gas-fueled units in the Dallas-Fort Worth area. In March 2008, the EPA made the eight-hour ozone standards more stringent. In January 2010, the EPA proposed to further reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage; however, in September 2011, the White House directed the EPA to withdraw this reconsideration. Since the EPA has not designated nonattainment areas and projects that SIP rules to address attainment of the 2008 standards will not be required until June 2015, we cannot yet predict the impact of this action on our 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 June 2013, pursuant to which compliance will be required by 2017, according to the EPA's implementation timeline. We cannot predict the impact of the new standards on our business, results of operations or financial condition until the TCEQ adopts (if required) an implementation plan with respect to the standards.

In 2005, the EPA 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 (MACT) rules by March 2011 and finalize those rules by November 2011, as subsequently postponed to December 2011. In March 2011, the EPA issued for comment a proposed rule for coal and oil-fueled electric generation units (Utility MACT). In December 2011, the EPA finalized the Utility MACT rule (now called the Mercury and Air Toxics Standard or MATS). MATS regulates the emissions of mercury, nonmercury metals, hazardous organic compounds and acid gases. Any additional control equipment retrofits on our lignite/coal-fueled generation units required to comply with MATS as finalized would need to be installed within three to four years from the April 16, 2012 effective date of the rule. We continue to evaluate the measures necessary to comply with MATS, which are expected to require substantial capital expenditures, and have not finalized cost estimates. As with many EPA regulations, there may be requests for a stay or reconsideration of the rule or petitions to the courts. We cannot predict if these actions will occur or, if they do, the outcome.


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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 requirements of the Clean Air Act. The EPA disapproved the Texas standard permit for pollution control projects. We hold several permits issued pursuant to the TCEQ standard permit conditions for pollution control projects. We have 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. We have also formally asked the EPA to stay, reconsider or clarify its disapproval. If the EPA declines to stay or reconsider its disapproval, we asked the EPA to clarify whether it intends that entities, including us, who obtained such permits for pollution control projects should stop operating the pollution control equipment permitted under the standard permit conditions. We cannot predict the outcome of the litigation or the EPA's response to our 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. We, 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. We have also applied for and received the generation facility-specific permit amendments. We have 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. We cannot predict the outcome of, or timing of the court's ruling in, this litigation. Also see Note 11 to Financial Statements for discussion of a petition filed in January 2012 by the Sierra Club in a Texas district court challenging the TCEQ's issuance of our permit amendments.


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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. We hold 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. We have 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 is consistent with the Clean Air Act. If the EPA's action stands, and if it causes us to undertake additional permitting activity and install additional emissions control equipment at our affected generation facilities, we could incur material capital expenditures. We cannot predict the outcome of this litigation.

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

Water

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

In 2010, we obtained a renewed and amended permit for discharge of waste water from our Oak Grove generation facility. Opponents to that permit renewal have initiated a challenge in Travis County, Texas District Court. We and the State of Texas are defending the issuance of the permit. We cannot predict the outcome of the litigation. If the permit is ultimately rejected by the courts, and we are required to undertake additional permitting activity and install additional temperature-control equipment, we could incur material capital expenditures, which could result in material effects on our results of operations, liquidity and financial condition. (See Note 11 to Financial Statements.)

Recent changes to federal rules pertaining to the Spill Prevention, Control and Countermeasure (SPCC) plans for oil-filled electrical equipment and bulk storage facilities for oil required updating of certain of our facilities. We have developed and implemented SPCC plans as required for those substations, work centers and distribution systems, and we are currently in compliance with the new rules that became effective in November 2011.


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Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQ and the EPA. We believe we possess all necessary permits for these activities from the TCEQ for our present operations. Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities were published by the EPA in 2004. As prescribed in the regulations, we began implementing a monitoring program to determine the future actions that might need to be taken to comply with these regulations. In January 2007, a federal court ruled against the EPA in a lawsuit brought by environmental groups challenging aspects of these regulations, and in July 2007, the EPA announced that it was suspending the regulations pending further rulemaking. The 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 their best professional judgment in reviewing applications and issuing permits under Section 316(b). In April 2010, the EPA entered into a settlement agreement that requires it to propose new rules under Section 316(b) by March 2011 and to finalize those rules by July 2012. In March 2011, the EPA issued for comment the proposed regulations. Although the proposed rule does not mandate a certain control technology, it does require site-specific assessments of technology feasibility on a case-by-case basis at the state level. Compliance with this rule would be required beginning eight years following promulgation. We cannot predict the substance of the final regulations or the impact they may have on our results of operations, liquidity or financial condition.


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Radioactive Waste

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

The nuclear industry is developing ways to store used nuclear fuel on site at nuclear generation facilities, primarily through the use of dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation in the US. Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear fuel storage capability is sufficient for the foreseeable future.

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

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

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

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. We do not know, at this time, the scope of these requirements, nor are we able to estimate the potential cost (which could be material) of complying with any such new requirements.

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Environmental Capital Expenditures

Capital expenditures for our environmental projects totaled $142 million in 2011 and are expected to total approximately $300 million in 2012 related to the CSAPR, MATS and other environmental regulations.


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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 impact on our operations, liquidity, financial results and financial condition, or could cause our 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

Our substantial indebtedness could adversely affect our ability to fund our operations, limit our ability to react to changes in the economy or our industry (including changes to environmental regulations), limit our ability to raise additional capital and adversely impact our ability to meet obligations under the various debt agreements governing our debt.

We are highly leveraged. As of December 31, 2011, our consolidated principal amount of debt (short-term borrowings and long-term debt, including amounts due currently) totaled $36.7 billion (see Note 10 to Financial Statements), which does not include $6.1 billion principal amount of debt of Oncor. Our substantial indebtedness could have significant consequences, including:

making it more difficult for us to make payments on our debt;
requiring a substantial portion of our cash flow to be dedicated to the payment of principal and interest on our debt, thereby reducing our ability to use our cash flow to fund operations, capital expenditures, future business opportunities and execution of our growth strategy;
increasing our vulnerability to adverse economic, industry or competitive conditions or developments, including changes to environmental regulations;
limiting our ability to make strategic acquisitions or causing us to make non-strategic divestitures;
limiting our ability to develop new generation facilities;
limiting our ability to obtain additional financing for working capital (including collateral postings), capital expenditures, product development, debt service requirements, acquisitions and general corporate or other purposes, or to refinance existing debt, and
limiting our ability to adjust to changing market and industry conditions (including changes to environmental regulations) and placing us at a competitive disadvantage compared to competitors who are less highly leveraged and who, therefore, may be able to operate at a lower overall cost (including debt service) and take advantage of opportunities that we cannot.

We may not be able to repay or refinance our debt as or before it becomes due, or obtain additional financing, particularly if forward natural gas prices do not significantly increase and/or if environmental regulations are adopted that result in significant capital requirements.

We may not be able to repay or refinance our debt as or before it becomes due, or we may only be able to refinance such amounts on terms that will increase our cost of borrowing or on terms that may be more onerous. Our ability to successfully implement any future refinancing of our debt will depend, among other things, on our financial condition and operating performance, which is subject to prevailing economic and competitive conditions, and to certain financial, business and other factors beyond our control, including, without limitation, wholesale electricity prices in ERCOT (which are primarily driven by the price of natural gas and ERCOT market heat rates), environmental regulations and general conditions in the credit markets. Refinancing may also be difficult because of the slow economic recovery, the possibility of rising interest rates and the impending significant debt maturities of numerous other borrowers. Because our credit ratings are significantly below investment grade, we may be more heavily exposed to these refinancing risks than other borrowers. In addition, the timing of additional financings may require us to pursue such financings at inopportune times.


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As of December 31, 2011, a substantial amount of our long-term debt matures in the next few years, including approximately $120 million principal amount of debt maturing in 2012-2013, approximately $4.3 billion principal amount of debt maturing in 2014 and approximately $3.3 billion principal amount of debt maturing in 2015. A substantial amount of our debt is comprised of debt incurred under the TCEH Senior Secured Facilities. In April 2011, we were able to secure an extension of a significant portion of the commitments and loans under the TCEH Senior Secured Facilities. However, even after taking the extension into account, we still have a significant amount of commitments and loans under the TCEH Senior Secured Facilities that will mature in 2013 and 2014 because a significant portion of the commitments (approximately $645 million maturing in 2013) and loans (approximately $3.85 billion principal amount maturing in 2014) were not extended. In addition, notwithstanding the extension, the extended commitments and loans could mature earlier as described in the next paragraph. Moreover, while we were able to extend a significant portion of the commitments and loans under the TCEH Senior Secured Facilities, the extensions were only for two years. As a result, we have a substantial principal amount of debt that matures in 2016 (approximately $1.7 billion) and 2017 (approximately $16.7 billion, including $947 million under the TCEH Letter of Credit Facility that is held in restricted cash).

The extended loans under the TCEH Senior Secured Facilities include a "springing maturity" provision pursuant to which in the event that (a) more than $500 million aggregate principal amount of the TCEH 10.25% Notes or more than $150 million aggregate principal amount of the TCEH Toggle Notes (in each case, other than notes held by EFH Corp. or its controlled affiliates as of March 31, 2011 to the extent held as of the determination date), as applicable, remain outstanding as of 91 days prior to the maturity date of the applicable notes and (b) TCEH's consolidated total debt to consolidated EBITDA ratio (as defined in the TCEH Senior Secured Facilities) is greater than 6.00 to 1.00 at such applicable determination date, then the maturity date of the extended loans will automatically change to 90 days prior to the maturity date of the applicable notes. As a result of this "springing maturity" provision, we may lose the benefit of the extension of the commitments and loans under the TCEH Senior Secured Facilities if we are unable to refinance the requisite portion of the TCEH 10.25% Notes and TCEH Toggle Notes (collectively, the TCEH Senior Notes) by the applicable deadline. The TCEH 10.25% Notes mature on November 1, 2015, and the TCEH Toggle Notes mature on November 1, 2016. If holders of the TCEH Senior Notes are unwilling to extend the maturities of their notes, then, to avoid the "springing maturity" of the extended loans, we may be required to repay a substantial portion of the TCEH Senior Notes at prices above market or at par. There is no assurance that we will be able to make such payments, whether through cash on hand or additional financings. As of December 31, 2011, $3.125 billion and $1.568 billion aggregate principal amount of the TCEH 10.25% Notes and the TCEH Toggle Notes, respectively, were outstanding, excluding amounts held by affiliates.

Wholesale electricity prices in the ERCOT market have generally moved with the price of natural gas. Accordingly, the contribution to earnings and the value of our nuclear and lignite/coal-fueled generation assets are dependent in significant part upon the price of natural gas. Forward natural gas prices have generally trended downward since mid-2008 (from $10.90 per MMBtu in mid-2008 to $3.94 per MMBtu at December 31, 2011 for calendar year 2013). 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. 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 our generation assets. Specifically, low natural gas prices and their effect in ERCOT on wholesale electricity prices could have a material impact on the overall profitability of our generation assets for periods in which we do not have significant hedge positions. As of December 31, 2011, we have hedged only approximately 58% and 31% of our wholesale natural gas price exposure related to expected generation output for 2013 and 2014, respectively, based on currently governing CAIR regulation, and we do not have any significant amounts of hedges in place for periods after 2014. Consequently, a continuation, or further decline, of current forward natural gas prices could result in further declines in the values of TCEH's nuclear and lignite/coal-fueled generation assets and limit or hinder TCEH's ability to hedge its wholesale electricity revenues at sufficient price levels to support its significant interest payments and debt maturities, which could adversely impact TCEH's ability to obtain additional liquidity and refinance and/or extend the maturities of its outstanding debt.


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Aspects of our current financial condition may also be challenging to our efforts to obtain additional financing (or refinance or extend our existing financing) in the future. For example, our liabilities and those of EFCH exceed our and EFCH's assets as shown on our and EFCH's respective balance sheet prepared in accordance with US GAAP as of December 31, 2011. Our reported assets include $6.152 billion of goodwill as of December 31, 2011. In 2010, we 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 our cash flow projections and declines in market values of securities of comparable companies. The value of our goodwill will continue to depend on, among other things, wholesale electricity prices in the ERCOT market. Further, third party analyses of TCEH's business performed in connection with goodwill impairment testing in accordance with US GAAP, which have indicated that the principal amount of TCEH's outstanding debt exceeds its enterprise value, may make it more difficult for us to successfully access the capital markets to obtain liquidity and/or implement any refinancing or extensions of our debt or obtain additional financing. Our ability to obtain future financing is also limited by the value of our unencumbered assets. Almost all of our assets are encumbered (in some cases by both first and second liens), and we have a limited value of assets which could be used as additional collateral in future financing transactions.

Despite our current high debt level, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial debt.
We may be able to incur additional debt in the future. Although our 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 our existing debt levels, the related risks that we and holders of our existing debt now face could intensify.

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

Future transactions and initiatives that we may pursue may have significant effects on our business, capital structure, liquidity and/or results of operations. For example, in addition to the exchanges, repurchases and extensions of our debt that are described in Note 10 to Financial Statements, we have 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 refinancing transactions (including extensions of maturity dates of our 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 us in a material manner. Moreover, the effects of any of these transactions or initiatives could be material and adverse to holders of our debt and could be disproportionate, and directionally different, with respect to one class or type of debt than with respect to others.

Our debt agreements and the Oncor "ring-fencing" measures contain restrictions that limit flexibility in operating our businesses.

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

incur additional 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 our 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 10 to Financial Statements for a description of these covenants and other restrictions.


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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 environmental regulations, and there can be no assurance that TCEH will comply with this ratio. As of December 31, 2011, TCEH's consolidated secured debt to consolidated EBITDA ratio was 5.78 to 1.00, which compares to the maximum consolidated secured debt to consolidated EBITDA ratio of 8.00 to 1.00 currently permitted under the TCEH Senior Secured Facilities. The secured debt portion of the ratio excludes (a) up to $1.5 billion of debt secured by a first-priority lien (including the TCEH Senior Secured Notes) if the proceeds of such debt are used to repay term loans or deposit letter of credit loans under the TCEH Senior Secured Facilities and (b) debt secured by a lien ranking junior to the TCEH Senior Secured Facilities, including the TCEH Senior Secured Second Lien Notes. For the year ended December 31, 2012, the maximum consolidated secured debt to consolidated EBITDA ratio permitted under the TCEH Senior Secured Facilities continues to be 8.00 to 1.00.

A breach of any of these covenants or restrictions could result in an event of default under one or more of our debt agreements, including as a result of cross default provisions. Upon the occurrence of an event of default under one of these debt agreements, our 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 or accelerations under our other debt. If we 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 all borrowings, we would likely not have sufficient assets and funds to repay those borrowings.

In addition, as described in Note 1 to Financial Statements, 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, many of which were agreed to and required by the PUCT's Order on Rehearing in Docket No. 34077, include, among other things:

Oncor Holdings' and Oncor's board of directors being comprised of a majority of directors that are independent from the Texas Holdings Group, EFH Corp. and its other subsidiaries;
Oncor being treated as an unrestricted subsidiary with respect to EFH Corp.'s and EFIH's debt;
Oncor not being restricted from incurring its own debt;
Oncor not guaranteeing or pledging any of its assets to secure the debt of any member of the Texas Holdings Group;
restrictions on distributions by Oncor, and the right of the independent members of Oncor's board of directors and the largest non-majority member of Oncor to block the payment of distributions to Oncor Holdings (i.e., such distributions not being available to EFH Corp. under certain circumstances), and
restrictions on the ability to sell a majority interest in Oncor until October 2012.

Lenders and holders of our debt have in the past alleged, and might allege in the future, that we are not operating in compliance with covenants in our debt agreements or make allegations against our directors and officers of breach of fiduciary duty. In addition, holders of credit derivative securities related to our debt securities (including credit default swaps) have in the past claimed, and might claim in the future, that a credit event has occurred under such credit derivative securities. In each case, even if the claims have no merit, these claims could cause the trading price of our debt securities to decline, adversely affect our ability to raise additional capital and/or refinance our existing debt or require us to repay certain intercompany loans.

Lenders or holders of our debt have in the past alleged, and might allege in the future, that we are not operating in compliance with the covenants in our debt agreements, that a default under our debt agreements has occurred or that our or our subsidiaries' boards of directors or similar bodies or officers are not properly discharging their fiduciary duties, or make other allegations regarding our business, including for the purpose, and potentially having the effect, of causing a default under our debt or other agreements, accelerating the maturity of such debt, protecting claims of debt issued at a certain entity or entities in our capital structure at the expense of debt claims elsewhere in our capital structure and/or obtaining economic benefits from us. These claims have included as recently as the first quarter of 2012, and may include in the future, among other things, claims that certain loans from TCEH to EFH Corp. were fraudulent transfers and should be repaid to TCEH, authorization of these loans violates the fiduciary duties of EFCH's and TCEH's boards of directors or the loans were in violation of the terms of our debt agreements. In the event a lender were to prevail on these claims, EFH Corp. may immediately be required to repay these intercompany loans to TCEH and be prevented from further borrowings under such loans. Further, holders of credit derivative securities related to our debt securities (including credit default swaps) have in the past claimed, and may claim in the future, that a credit event has occurred under such credit derivative securities based on our financial condition. Even if these claims are without merit, they could nevertheless cause the trading price of our debt to decline and adversely affect our ability to raise additional capital and/or refinance our existing debt.


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

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

If cash flows and capital resources are insufficient to fund our debt obligations, we could face substantial liquidity problems and might be forced to reduce or delay investments and capital expenditures, or to dispose of assets or operations, seek additional capital or restructure or refinance debt. These alternative measures may not be successful, may not be completed on economically attractive terms or may not be adequate for us to meet our debt obligations when due. Additionally, our debt agreements limit the use of the proceeds from many dispositions of assets or operations. As a result, we may not be permitted to use the proceeds from these dispositions to satisfy our debt obligations.

Further, if we suffer or appear to suffer, from a lack of available liquidity, the evaluation of our creditworthiness by counterparties and rating agencies could be adversely impacted. In particular, such concerns by existing and potential counterparties could significantly limit TCEH's wholesale market activities, including its natural gas price hedging program.

Under the terms of the indentures governing the TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities, TCEH is restricted from making certain payments to EFH Corp. EFH Corp. may be required to repay all or a portion of the intercompany notes it owes to TCEH.

EFH Corp. is a holding company and substantially all of its reported consolidated assets are held by its subsidiaries. As of December 31, 2011, TCEH and its subsidiaries held approximately 81% of EFH Corp.'s reported consolidated assets, and for the year ended December 31, 2011, TCEH and its subsidiaries represented all of EFH Corp.'s reported consolidated revenues. Accordingly, TCEH and its subsidiaries constitute an important funding source for EFH Corp. to satisfy its obligations. However, under the terms of the indentures governing the TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities, TCEH is restricted from making certain payments to EFH Corp., except in the form of certain loans to cover certain of EFH Corp.'s obligations (and dividends and distributions in certain other limited circumstances if permitted by applicable state law). Further, the indentures governing the TCEH Senior Notes, Senior Secured Notes and Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities do not permit such intercompany loans to service EFH Corp.'s debt unless required for EFH Corp. to pay principal, premium and interest when due on debt incurred by EFH Corp. to finance the Merger or that was in existence prior to the Merger, or any debt incurred by EFH Corp. to replace, refund or refinance such debt. Such loans are also permitted in order to service other debt, subject to limitations on the amount of the loans. In addition, TCEH is prohibited from making certain loans to EFH Corp. if certain events of default under the indentures governing the TCEH Senior Notes, Senior Secured Notes or Senior Secured Second Lien Notes or the terms of the TCEH Senior Secured Facilities have occurred and are continuing. As of the date hereof, none of these events of default has occurred or is continuing.

In addition, the TCEH Senior Secured Facilities contain provisions related to TCEH's intercompany notes receivable from EFH Corp., which are guaranteed by EFCH and EFIH on a senior unsecured basis and are demand notes, which means that TCEH can require payment of all or a portion of these notes at any time. As of February 15, 2012, the aggregate principal amount of these intercompany notes was approximately $960 million. These provisions include the following related to cash loaned by TCEH to EFH Corp. for (i) debt principal and interest payments (P&I Note) and (ii) other general corporate purposes (SG&A Note and, together with the P&I Note, the Intercompany Notes):

TCEH will not make any further loans under the SG&A Note to EFH Corp.;
borrowings outstanding under the P&I Note will not exceed $2 billion in the aggregate at any time; and
the sum of (a) the outstanding senior secured indebtedness (including guarantees) issued by EFH Corp. or any subsidiary of EFH Corp. (including EFIH) secured by a second-priority lien on the equity interests that EFIH owns in Oncor Holdings (EFIH Second-Priority Debt) and (b) the aggregate outstanding amount of the Intercompany Notes will not exceed, at any time, the maximum amount of EFIH Second-Priority Debt permitted by the indenture governing the EFH Corp. Senior Secured Notes as in effect on April 7, 2011.


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If TCEH is not able to continue making intercompany loans to EFH Corp. as a result of the restrictions in the amendment or otherwise, EFH Corp. may not have sufficient cash flows to meet its obligations. If EFH Corp., or EFIH or EFCH (as guarantors), were not able to repay TCEH, it could negatively impact TCEH's cash flows and its ability to meet its obligations. A failure by EFH Corp. to repay the intercompany notes when required could result in defaults under EFH Corp.'s other debt, including debt that EFCH and EFIH guarantee. It would also likely result in EFCH's and EFIH's guarantees of the intercompany notes being called, which could cause defaults under EFCH's and EFIH's other debt.

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

EFH Corp. is a holding company and substantially all of its consolidated assets are held by its subsidiaries. As of December 31, 2011, EFIH and its subsidiaries held approximately 13% of EFH Corp.'s reported consolidated assets, which assets consist primarily of EFIH's investment in Oncor Holdings. Accordingly, EFIH constitutes an important funding source of EFH Corp. for a significant amount of its cash flows and relies on such cash flows in order to satisfy its obligations. However, under the terms of the indentures governing the EFIH Notes, EFIH is restricted from making certain payments, including dividends and loans, to EFH Corp., except in limited circumstances.

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

EFH Corp. depends upon Oncor for a significant amount of its cash flows and relies on such cash flows in order to satisfy its obligations. However, EFH Corp. has a very limited ability to control the activities of Oncor. As part of the "ring-fencing" measures implemented by EFH Corp. and Oncor, a majority of the members of Oncor's board of directors are required to meet the New York Stock Exchange requirements for independence in all material respects, and the unanimous, or majority, consent of such directors is required for Oncor to take certain actions. In addition, any new independent directors are required to be appointed by the nominating committee of Oncor Holdings' board of directors, a majority of whose members are independent directors. No member of EFH Corp.'s management is a member of Oncor's board of directors. Under Oncor Holdings' and Oncor's organizational documents, EFH Corp. has limited indirect consent rights with respect to the activities of Oncor, including (i) new issuances of equity securities by Oncor, (ii) material transactions with third parties involving Oncor outside of the ordinary course of business, (iii) actions that cause Oncor's assets to be subject to an increased level of jurisdiction of the FERC, (iv) any changes to the state of formation of Oncor, (v) material changes to accounting methods not required by US GAAP, and (vi) actions that fail to enforce certain tax sharing obligations between Oncor and EFH Corp. In addition, Oncor's organizational agreements contain restrictions on Oncor's ability to make distributions to its members, including indirectly to EFH Corp.

Risks Related to Our Structure

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

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

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


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

Upon the consummation of the Merger, EFH Corp. and Oncor implemented certain structural and operational "ring-fencing" measures, including certain measures required by the PUCT's Order on Rehearing in Docket No. 34077, 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 in 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, which is required to be, and is, comprised of a majority of directors that are independent from EFH Corp. The organizational documents of Oncor give these independent directors, acting by majority vote, and, during certain periods, any director designated by Texas Transmission, the express right to prevent distributions from Oncor if they determine that it is in the best interests of Oncor to retain such amounts to meet expected future requirements. Accordingly, there can be no assurance that Oncor will make any distributions to EFH Corp.

In addition, Oncor's organizational documents limit Oncor's distributions to its owners, including EFH Corp., through December 31, 2012 to an amount not to exceed Oncor's net income (determined in accordance with 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 2009, the PUCT awarded Oncor the right to construct transmission lines and facilities associated with its CREZ Transmission Plan, the cost of which is estimated by Oncor to be approximately $2.0 billion (see discussion in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters"). With the award, Oncor has incurred additional debt. In addition, Oncor may incur additional debt in connection with other investments in infrastructure or technology. Accordingly, while Oncor is required to maintain a specified debt-to-equity ratio, there can be no assurance that Oncor's equity balance will be sufficient to maintain the required debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, thereby restricting Oncor from making any distributions to EFH Corp. In addition, any increase in Oncor's interest expense may reduce the amounts available to be distributed to EFH Corp.

Oncor's ring-fencing measures may not work as planned.

In 2007, EFH Corp. and Oncor implemented certain structural and operational "ring-fencing" measures, including certain measures required by the PUCT's Order on Rehearing in Docket No. 34077, 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 in place to mitigate Oncor's credit exposure to the Texas Holdings Group and to reduce the risk that a court would order any of the Oncor Ring-Fenced Entities' assets and liabilities to be substantively consolidated with those of any member of the Texas Holdings Group in the event that a member of the Texas Holdings Group were to become a debtor in a bankruptcy case. Nevertheless, bankruptcy courts have broad equitable powers, and as a result, outcomes in bankruptcy proceedings are inherently difficult to predict. Accordingly, if any member of the Texas Holdings Group were to become a debtor in a bankruptcy case, there can be no assurance (however remote in consideration of the ring-fencing measures) that a court would not order an Oncor Ring-Fenced Entity's assets and liabilities to be substantively consolidated with those of such member of the Texas Holdings Group or that a proceeding would not result in a disruption of services Oncor receives from or jointly with affiliates. See Note 1 to Financial Statements for additional information on ring-fencing measures.

In addition, Oncor's access to capital markets and cost of debt could be directly affected by its credit ratings. Any adverse action with respect to Oncor's credit ratings would generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease. Oncor's credit ratings are currently substantially higher than those of the Texas Holdings Group. If credit rating agencies were to change their views of Oncor's independence from any member of the Texas Holdings Group, Oncor's credit ratings would likely decline. Despite the ring-fencing measures, rating agencies could take an adverse action with respect to Oncor's credit ratings in response to liability management or other activities by EFH Corp. or any of its subsidiaries, including the incurrence of debt by EFH Corp. and/or EFIH which is secured by a lien on the equity of Oncor Holdings held by EFIH. In the event any such adverse action takes place and causes Oncor's borrowing costs to increase, it may not be able to recover these increased costs if they exceed Oncor's PUCT-approved cost of debt determined in its most recent rate case or subsequent rate cases.


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Risks Related to Our Businesses

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

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

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

The Texas Legislature meets every two years. The next regular legislative session is scheduled to begin in January 2013; however, at any time the governor of Texas may convene a special session of the Legislature. During any regular or special session bills may be introduced that, if adopted, could materially affect our businesses. There can be no assurance that future action of the Texas Legislature will not result in legislation that could have a material effect on our businesses.

Our cost of compliance with existing and new environmental laws could materially affect our results of operations, liquidity and financial condition.

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

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

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

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

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Our results of operations, liquidity and financial condition may be materially affected if new federal and/or state legislation or regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged damage to persons or property resulting from greenhouse gas emissions.

There is a concern nationally and internationally about global climate change and how greenhouse gas (GHG) emissions, such as carbon dioxide (CO2), contribute to global climate change. Several bills addressing climate change have been introduced in the 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 filed in recent years asserting damage claims related to GHG emissions, and the results in those proceedings could establish adverse precedent that might apply to companies (including us) that produce GHG emissions.

The EPA has 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. 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. PSD permitting requirements 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 has also issued regulations that require certain categories of GHG emitters (including our lignite/coal-fueled generation facilities) to monitor and report their annual GHG emissions.

The EPA also announced in late 2010 its intent to promulgate 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. We cannot predict what limits or guidelines the EPA might adopt. If limits or guidelines become applicable to our generation facilities and require us to install new control equipment or substantially alter our operations, it could have a material effect on our results of operations, liquidity and financial condition.

We produce GHG emissions from the combustion of fossil fuels at our generation facilities. Because a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities, our results of operations, liquidity and financial condition could be materially affected by the enactment of any legislation or regulation that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes upon those that produce GHG emissions. For example, to the extent a cap-and-trade program is adopted, we may be required to incur material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with such a program. The EPA regulation of GHGs under the Clean Air Act, or judicially imposed sanctions or damage awards related to GHG emissions, may require us to make material expenditures to reduce our GHG emissions. In addition, if a significant number of our customers or others refuse to do business with us because of our GHG emissions, it could have a material effect on our results of operations, liquidity or financial condition.

Litigation related to environmental issues, including claims alleging that GHG emissions constitute a public nuisance by contributing to global climate change, has increased in recent years. American Electric Power Co. v. Connecticut, Comer v. Murphy Oil USA and Native Village of Kivalina v. ExxonMobil Corporation all involve nuisance claims for damages purportedly caused by the defendants' emissions of GHGs. Although we are not currently a party to any pending lawsuits alleging that GHG emissions are a public nuisance, these lawsuits could establish precedent that might affect our business or industry generally. Other similar lawsuits have involved claims of property damage, personal injury, challenges to issued permits and citizen enforcement of environmental laws and regulations. We cannot predict the ultimate outcome of the pending proceedings. If we are sued in these or similar proceedings and are ultimately subject to an adverse ruling, we could be required to make substantial capital expenditures for emissions control equipment, halt operations and/or pay substantial damages. Such expenditures or the cessation of operations could adversely affect our results of operations, liquidity and financial condition.


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If we are required to comply with the EPA's Cross-State Air Pollution Rule (CSAPR) as revised by the EPA in February 2012, we will likely incur material capital expenditures and operating costs and experience material revenue decreases due to reduced generation and wholesale power sales volumes.

In July, 2011, the EPA issued the CSAPR. In February 2012, the EPA released a final rule (Final Revisions) and a direct-to-final rule (Direct Final Rule) revising certain aspects of the CSAPR, including emissions budgets for the State of Texas as discussed in Items 1 and 2, "Business and Properties - Environmental Regulations and Related Considerations - Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions." If the EPA receives significant adverse comments on the Direct Final Rule, it will be withdrawn and its provisions considered in a proposed rule subject to normal notice-and-comment rulemaking procedures. In total, the emissions budgets established by the Final Revisions along with the Direct Final Rule would require our fossil-fueled generation units to reduce (i) their annual SO2 and NOx emissions by approximately 120,600 tons (56 percent) and 9,000 tons (22 percent), respectively, compared to 2010 actual levels, and (ii) their seasonal NOx emissions by approximately 3,300 tons (18 percent), compared to 2010 levels. We could comply with these emissions limits either through physical reductions or through the purchase of emissions credits from third parties, but the volume of SO2 credits that may be purchased from sources outside of Texas is subject to limitations starting in 2014. Because the CSAPR is currently stayed by the D.C. Circuit Court, the Final Revisions and the Direct Final Rule do not impose any immediate legal or compliance requirements on Luminant, the State of Texas, or other affected parties. We cannot predict whether, when, or in what form the CSAPR, the Final Revisions, or the Direct Final Rule will take effect.

Material capital expenditures would be required to comply with the CSAPR, as revised in February 2012, as well as with other pending and expected environmental regulations, including MATS. In 2011, total capital expenditures for environmental projects totaled $142 million. Analysis is ongoing regarding expected capital expenditures relating to the CSAPR, the Final Revisions and the Direct Final Rule, the status of which is uncertain given the pending legal proceeding, and the final MATS rule, which was published in February 2012. We currently estimate that total capital expenditures related to the CSAPR, the Final Revisions, the Direct Final Rule, MATS, and other environmental regulations will be approximately $300 million in 2012. Prior to the publication of the final MATS rule, we estimated that expenditures of more than $1.5 billion before the end of the decade in environmental control equipment would be required to comply with regulatory requirements, including the CSAPR and MATS. We are currently evaluating this estimate in light of the final MATS rule, the Final Revisions and the Direct Final Rule.

We cannot predict (i) whether the legal challenge to the CSAPR will be ultimately successful on the merits, (ii) when the D.C. Circuit Court will issue a final ruling on the validity of the CSAPR and/or (iii) the effective date of the CSAPR if it is ultimately implemented. As a result, there can be no assurance that we will not be required to implement a CSAPR compliance plan in a short time frame or that such plan will not materially affect our results of operations, liquidity or financial condition.

Luminant's mining permits are subject to RRC review.

The RRC reviews on an ongoing basis whether Luminant is compliant with RRC rules and regulations and whether it has met all of the requirements of its mining permits. Any revocation of a mining permit would mean that Luminant would no longer be allowed to mine lignite at the applicable mine to serve its generation facilities. Such event would have a material effect on our results of operations, liquidity and financial condition.

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

We are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, and environmental issues, and other claims for injuries and damages, among other matters. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these evaluations and estimates, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These evaluations 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 evaluations and estimates. The settlement or resolution of such claims or proceedings may have a material effect on our results of operations. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment in the State of Texas poses a significant business risk.


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

We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings. See Item 3, "Legal Proceedings - Regulatory Investigations and Reviews." While we cannot predict the outcome of any regulatory investigation or administrative proceeding, any such regulatory investigation or administrative proceeding could result in us incurring material penalties and/or other costs and have a material effect on our results of operations, liquidity and financial condition.

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

TCEH (our largest business) is not guaranteed any rate of return on capital investments in its businesses. We market and trade electricity and natural gas, including electricity from our own generation facilities and generation contracted from third parties, as part of our wholesale markets operation. TCEH's results of operations depend in large part upon 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, among other things, 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 our generation facilities is purchased under short-term contracts. Prices of fuel (including diesel, natural gas, coal and nuclear fuel) may also be volatile, and the price we can obtain for electricity sales may not change at the same rate as changes in fuel costs. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting obligations.

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

volatility in natural gas prices;
volatility in ERCOT 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 commodity 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 we operate our facilities, including curtailed operation due to market pricing, environmental, safety or other factors;
changes in generation efficiency;
outages or otherwise reduced output from our generation facilities or those of our competitors;
changes in the credit risk or payment practices of market participants;
changes in production and storage levels of natural gas, lignite, coal, crude oil, diesel and other refined products;
natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and
federal, state and local energy, environmental and other regulation and legislation.


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All of our generation facilities are located in the ERCOT market, a market with limited interconnections to other markets. Wholesale electricity prices in the ERCOT market have generally moved with the price of natural gas because marginal electricity demand is generally supplied by natural gas-fueled generation facilities. Accordingly, our earnings and the value of our nuclear and lignite/coal-fueled generation assets, which provided a substantial portion of our supply volumes in 2011, are dependent in significant part upon the price of natural gas. Forward natural gas prices have generally trended downward since mid-2008 (from $10.90 per MMBtu in mid-2008 to $3.94 per MMBtu at December 31, 2011 for calendar year 2013). 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. 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.

Wholesale electricity prices also have generally moved with ERCOT market heat rates, which could fall if demand for electricity were to decrease or if more efficient generation facilities are built in ERCOT. Accordingly, our earnings and the value of our nuclear and lignite/coal-fueled generation assets are also dependent in significant part upon market heat rates. As a result, our nuclear and lignite/coal-fueled generation assets could significantly decrease in profitability and value if ERCOT market heat rates decline.

The percentage of our wholesale natural gas price exposure that is hedged declines significantly in future periods, which could result in reduced earnings (and related cash flows) and adversely affect our ability to pay principal and interest on our debt in those periods and refinance our debt if wholesale natural gas prices do not increase.

Our hedging activities, in particular our natural gas price hedging program, are designed to mitigate the adverse effect on earnings (and related cash flows) of low wholesale electricity prices (due to low natural gas prices). These market conditions are challenging to the long-term profitability of our generation assets. Specifically, low natural gas prices and their effect in ERCOT on wholesale power prices could have a material impact on the overall profitability of our generation assets for periods in which we do not have significant hedge positions. While we have significantly hedged our natural gas price exposure for 2012 (approximately 86% under CAIR regulation), as of December 31, 2011, we have hedged only approximately 58% and 31% of our wholesale natural gas price exposure related to expected generation output for 2013 and 2014, respectively, and do not have any significant amounts of hedges in place for periods after 2014.

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. 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. Consequently, a continuation, or further decline, of current forward natural gas prices could result in further declines in the values of TCEH's nuclear and lignite/coal-fueled generation assets and limit or hinder TCEH's ability to hedge its wholesale electricity revenues at sufficient price levels to support its significant interest payments and debt maturities, which could adversely impact TCEH's ability to obtain additional liquidity and refinance and/or extend the maturities of its outstanding debt. Consequently, our ability to fund our operations, meet our obligations under our debt agreements, refinance or extend our substantial indebtedness and obtain additional financing in the future is dependent on increases in the current and expected future price of natural gas.

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

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


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

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

Our collateral requirements for hedging arrangements could be materially impacted if the rules implementing the Financial Reform Act broaden the scope of the Act's provisions regarding the regulation of over-the-counter financial derivatives, making certain provisions applicable to end-users like us.

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 we use 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. We are evaluating whether or not the type of asset-backed OTC derivatives that we use 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 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 we were required to post cash collateral on our swap transactions with swap dealers, our liquidity would likely be materially impacted, and our ability to enter into derivatives to hedge our commodity and interest rate risks would be significantly limited.

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


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

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

unscheduled outages or unexpected costs due to equipment, mechanical, structural, cybersecurity 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 or cybersecurity attacks;
limitations on the amounts and types of insurance coverage commercially available, and
uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives.

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

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

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

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 our reputation. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage.

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

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

Insurance, warranties or performance guarantees may not cover all or any of the lost revenues or increased expenses 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 our control.

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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 effect on our results of operations, liquidity and financial condition.

Many of our facilities were constructed many years ago and require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could materially affect our results of operations, liquidity and financial condition.

We 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 or cybersecurity attacks). The unexpected requirement of large capital expenditures could materially affect our results of operations, liquidity and financial condition.

If we make any major modifications to our power generation facilities, we 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 us incurring substantial additional capital expenditures.

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

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

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

Our results of operations, liquidity and financial condition may be materially affected by insufficient water supplies.

Supplies of water are important for our generation facilities. Water in Texas is limited and various parties have made conflicting claims regarding the right to access and use such limited supplies of water. In addition, Texas has been experiencing sustained, severe drought conditions that may affect the water supply for certain of our generation facilities if adequate rain does not fall in the watershed that supplies the affected areas. If we are unable to access sufficient supplies of water, it could restrict, prevent or increase the cost of operations at certain of our generation facilities.

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

The rates charged by Oncor are regulated by the PUCT and certain cities and are subject to cost-of-service regulation and annual earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Oncor's rates are regulated based on an analysis of Oncor's costs and capital structure, as reviewed and approved in a regulatory proceeding. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCT will judge all of Oncor's costs to have been prudently incurred, that the PUCT will not reduce the amount of invested capital included in the capital structure that Oncor's rates are based upon, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of Oncor's costs, including regulatory assets reported on Oncor's balance sheet, and the return on invested capital allowed by the PUCT. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters" for discussion of recent and pending rate-related filings with the PUCT.


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

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

As we seek to improve our financial condition, we intend to take steps to reduce our costs. While we have a number of initiatives underway to reduce costs, it will likely become increasingly difficult to identify and implement significant new cost savings initiatives. The implementation of performance improvement initiatives identified by management may not produce the desired reduction in costs and if unsuccessful, may instead result in significant additional costs as well as significant disruptions in our operations due to employee displacement and the rapid pace of changes to organizational structure and operating practices and processes. Such additional costs or operational disruptions could have an adverse effect on our results of operations, liquidity and financial condition.

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

Much of our information technology infrastructure is connected (directly or indirectly) to the Internet. Recently there have been numerous attacks on government and industry information technology systems through the Internet that have resulted in material operational, reputation and/or financial costs. While we have controls in place designed to protect our infrastructure and have not had any significant breaches, a breach of cyber/data security measures that impairs our information technology infrastructure could disrupt normal business operations and affect our ability to control our generation and transmission and distribution assets, access retail customer information and limit communication with third parties. Any loss of confidential or proprietary data through a breach could adversely affect our reputation, expose the company to material legal/regulatory claims, impair our ability to execute on business strategies and/or materially affect our results of operations, liquidity and financial condition.

As part of the continuing development of new and modified reliability standards, the FERC has approved changes to its Critical Infrastructure Protection reliability standards and has established standards for assets identified as “critical cyber assets.” Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day per violation) for failure to comply with mandatory electric reliability standards, including standards to protect the power system against potential disruptions from cyber and physical security breaches.

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

Our retail operations face competition for customers. Competitors may offer lower prices and other incentives, which, despite the business' long-standing relationship with customers, may attract customers away from us as is reflected in a 17% decline in customers (based on meters) served over the last three years.

In some retail electricity markets, our 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, we 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 us. Some of these competitors or potential competitors may be larger or better capitalized than we are. If there is inadequate potential margin in these retail electricity markets, it may not be profitable for us to compete in these markets.


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Our retail operations are subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to our reputation and/or the results of the retail operations.

Our 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. Our 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 our retail business may be adversely affected, customer confidence may be diminished, or our 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 its results of operations.

Our retail operations rely 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 the business and results of operations.

Our retail operations depend 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, our ability to sell and deliver electricity may be hindered, and we 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 we have 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 our customers could negatively impact customer satisfaction with our service.

Our retail operations offer bundled services to customers, with some bundled services offered at fixed prices and for fixed terms. If our costs for these bundled services exceed the prices paid by its customers, its results of operations could be materially affected.

Our retail operations offer customers a bundle of services that include, at a minimum, electricity plus transmission, distribution and related services. The prices we charge for the 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 our underlying cost to provide the components of such services.

The REP certification of our retail operations is subject to PUCT review.

The PUCT may at any time initiate an investigation into whether our retail operations comply with PUCT Substantive Rules and whether we have met all of the requirements for REP certification, including financial requirements. Any removal or revocation of a REP certification would mean that we would no longer be allowed to provide electricity service to retail customers. Such decertification could have a material effect on our results of operations, liquidity and financial condition.

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

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

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


44


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

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

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

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

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

EFH Corp.'s (or any applicable subsidiary's) credit ratings could be lowered, suspended or withdrawn entirely at any time by the rating agencies if in each rating agency's judgment, circumstances warrant. Downgrades in EFH Corp.'s or any of its 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 EFH Corp.'s large customers, suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions with us. If EFH Corp.'s (or any 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 or cash-related instruments, or counterparties could decline to do business with EFH Corp. (or such subsidiary).

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

Our businesses are capital intensive. We rely on access to financial markets and liquidity facilities as a significant source of liquidity for our capital requirements and other obligations not satisfied by cash-on-hand or operating cash flows. The inability to raise capital or access liquidity facilities, particularly on favorable terms, could adversely impact our liquidity and our ability to meet our obligations or sustain and grow our businesses and could increase capital costs. Our access to the financial markets and liquidity facilities could be adversely impacted by various factors, such as:

changes in financial markets that reduce available credit or the ability to obtain or renew liquidity facilities on acceptable terms;
economic weakness in the ERCOT or general US market;
changes in interest rates;
a deterioration, or perceived deterioration, of EFH Corp.'s (and/or its subsidiaries') creditworthiness or enterprise value;
a reduction in EFH Corp.'s or its applicable subsidiaries' credit ratings;
a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our liquidity facilities that affects the ability of such lender(s) to make loans to us;
volatility in commodity prices that increases margin or credit requirements;
a material breakdown in our risk management procedures, and
the occurrence of changes in our businesses that restrict our ability to access liquidity facilities.


45


Although we expect to actively manage the liquidity exposure of existing and future hedging arrangements, given the size of the natural gas price hedging program, any significant increase in the price of natural gas could result in us being required to provide cash or letter of credit collateral in substantial amounts. While these potential posting obligations are primarily supported by our 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 our creditworthiness could result in clearing agents or other counterparties requesting additional collateral. We have credit concentration risk related to the limited number of lenders that provide liquidity to support our hedging program. A deterioration of the creditworthiness of such lenders could materially affect our ability to continue such program on acceptable terms. An event of default by one or more of our hedge counterparties could result in termination-related settlement payments that reduce available liquidity if we owe amounts related to commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us. These events could have a material negative impact on our results of operations, liquidity and financial condition.

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

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

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

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

We provide pension benefits based on either a traditional defined benefit formula or a cash balance formula and also provide certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. Our costs of providing such benefits and related funding requirements are dependent upon numerous factors, assumptions and estimates and are subject to changes in these factors, assumptions and estimates, including the market value of the assets funding the 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 our pension and OPEB plans are subject to changes in financial market conditions. 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. Our costs of providing such benefits and related funding requirements are also subject to changing employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in financial market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods. See Note 18 to Financial Statements for further discussion of our pension and OPEB plans.

As discussed in Note 5 to Financial Statements, goodwill and/or other intangible assets not subject to amortization that we have recorded in connection with the Merger are subject to at least annual impairment evaluations. As a result, we could be required to write off some or all of this goodwill and other intangible assets, which may cause adverse impacts on our 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. Factors such as the economic climate, market conditions, including the market prices for wholesale electricity and natural gas and market heat rates, environmental regulation, and the condition of assets are considered when evaluating these assets for impairment. The actual timing and amounts of any goodwill impairments will depend on many sensitive, interrelated and uncertain variables. 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 impact on our reported results of operations and financial condition.


46


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

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

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

The Sponsor Group in the aggregate 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 aggregate ownership in interests of the general partner of Texas Holdings, the Sponsor Group taken as a whole has control over decisions regarding our operations, plans, strategies, finances and structure, including whether to enter into any corporate transaction, and will have the ability to prevent any transaction that requires the approval of EFH Corp.'s shareholders. The Sponsor Group is comprised of Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and GS Capital Partners, each of which acts independently of the others with respect to its investment in EFH Corp. and Texas Holdings.

Additionally, each member of the Sponsor Group is in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. Members of the Sponsor Group may also pursue acquisition opportunities that may be complementary to our businesses and, as a result, those acquisition opportunities may not be available to us. So long as the members of the Sponsor Group, or other funds controlled by or associated with the members of the Sponsor Group, continue to indirectly own, 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 our decisions.

Item 1B.
UNRESOLVED STAFF COMMENTS

None.



47


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. In January 2012, the petition filed by Paul and Lisa Rolke was dismissed. Although we cannot predict the outcome of these proceedings, we believe 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 our results of operations, liquidity or financial condition.

In January 2012, the Sierra Club filed a petition in Travis County, Texas District Court challenging the TCEQ's decision to issue permit amendments imposing limits on emissions during planned startup, shutdown and maintenance activities at Luminant's Big Brown, Monticello, Martin Lake and Sandow Unit 4 generation facilities. Although we cannot predict the outcome of this proceeding, we believe that the permit amendments are protective of the environment and in accordance with applicable law. There can be no assurance that the outcome of this matter would not result in an adverse impact on our results of operations, liquidity or financial condition.

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 we are unable to estimate any possible loss or predict the outcome of the litigation, we believe that the Sierra Club's claims are without merit, and we intend to vigorously defend this litigation. The litigation is currently stayed by the court. In addition, in February 2010, the Sierra Club informed Luminant that it may sue Luminant for allegedly violating federal Clean Air Act provisions in connection with Luminant's Big Brown generation facility. Subsequently, in December 2010, the Sierra Club informed Luminant that it may sue Luminant for allegedly violating federal Clean Air Act provisions in connection with Luminant's Monticello generation facility. In October 2011, the Sierra Club again informed Luminant that it may sue Luminant for allegedly violating federal Clean Air Act provisions in connection with Luminant's Big Brown and Monticello generation facilities. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.

See Items 1 and 2, "Business and Properties – Environmental Regulations and Related Considerations – Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions – Cross-State Air Pollution Rule" for discussion of our petition for review in the D.C. Circuit Court challenging the CSAPR and a motion to stay the effective date of the CSAPR, in each case as applied to Texas.

Regulatory Reviews

In June 2008, the EPA issued an initial 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. We are cooperating with the EPA and responding in good faith to the EPA's request, but we are unable to predict the outcome of this matter.

Other Matters

We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, is not anticipated to have a material effect on our results of operations, liquidity or financial condition.


48


Item 4.
MINE SAFETY DISCLOSURES

We currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities. These mining operations are regulated by the 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 ours, on a regular basis, and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Disclosure of MSHA citations, orders and proposed assessments are provided in Exhibit 95(a) to this Annual Report on Form 10-K.


49


PART II

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

EFH Corp.'s common stock is privately held and has no established public trading market.

See Note 12 to Financial Statements for discussion of the restrictions on EFH Corp.'s ability to pay dividends.

The number of holders of EFH Corp.'s common stock of as of February 20, 2012 was 120.

Item 6.
SELECTED FINANCIAL DATA
EFH CORP. AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
(millions of dollars, except ratios)
 
Successor
 
 
Predecessor
 
Year Ended December 31,
 
Period from
October 11,
2007 through
December 31, 2007
 
 
Period from
January 1,
2007 through
October 10, 2007

2011
 
2010
 
2009
 
2008
 
 
 
Operating revenues
$
7,040

 
$
8,235

 
$
9,546

 
$
11,364

 
$
1,994

 
 
$
8,044

Impairment of goodwill

 
(4,100
)
 
(90
)
 
(8,860
)
 

 
 

Income (loss) from continuing operations
(1,913
)
 
(2,812
)
 
408

 
(9,998
)
 
(1,361
)
 
 
699

Income from discontinued operations, net of
tax effect

 

 

 

 
1

 
 
24

Net income (loss)
(1,913
)
 
(2,812
)
 
408

 
(9,998
)
 
(1,360
)
 
 
723

Net (income) loss attributable to noncontrolling
interests

 

 
(64
)
 
160

 

 
 

Net income (loss) attributable to EFH Corp.
(1,913
)
 
(2,812
)
 
344

 
(9,838
)
 
(1,360
)
 
 
723

Ratio of earnings to fixed charges (a)

 

 
1.24

 

 

 
 
2.30

Cash provided by (used in) operating activities
from continuing operations
841

 
1,106

 
1,711

 
1,505

 
(450
)
 
 
2,265

Cash provided by (used in) financing activities
from continuing operations
(1,014
)
 
(264
)
 
422

 
2,837

 
33,865

 
 
1,394

Cash used in investing activities from
continuing operations
(535
)
 
(468
)
 
(2,633
)
 
(2,934
)
 
(34,563
)
 
 
(2,283
)
Capital expenditures, including nuclear fuel
$
684

 
$
944

 
$
2,545

 
$
3,015

 
$
716

 
 
$
2,542




50



EFH CORP. AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA (CONTINUED)
(millions of dollars, except ratios)
 
As of December 31,
 
2011
 
2010
 
2009
 
2008
 
2007
Total assets
$
44,077

 
$
46,388

 
$
59,662

 
$
59,263

 
$
64,804

Property, plant & equipment — net
$
19,427

 
$
20,366

 
$
30,108

 
$
29,522

 
$
28,650

Goodwill and intangible assets
$
7,997

 
$
8,552

 
$
17,192

 
$
17,379

 
$
27,319

Investment in unconsolidated subsidiary (Note 2)
$
5,720

 
$
5,544

 
$

 
$

 
$

Capitalization
 
 
 
 
 
 
 
 
 
Long-term debt, less amounts due currently
$
35,360

 
$
34,226

 
$
41,440

 
$
40,838

 
$
38,603

EFH Corp. common stock equity
(7,852
)
 
(5,990
)
 
(3,247
)
 
(3,673
)
 
6,685

Noncontrolling interests in subsidiaries
95

 
79

 
1,411

 
1,355

 

Total
$
27,603

 
$
28,315

 
$
39,604

 
$
38,520

 
$
45,288

Capitalization ratios
 
 
 
 
 
 
 
 
 
Long-term debt, less amounts due currently
128.1
 %
 
120.9
 %
 
104.6
 %
 
106.0
 %
 
85.2
%
EFH Corp. common stock equity
(28.4
)%
 
(21.2
)%
 
(8.2
)%
 
(9.5
)%
 
14.8
%
Noncontrolling interests in subsidiaries
0.3
 %
 
0.3
 %
 
3.6
 %
 
3.5
 %
 
%
Total
100.0
 %
 
100.0
 %
 
100.0
 %
 
100.0
 %
 
100.0
%
Short-term borrowings
$
774

 
$
1,221

 
$
1,569

 
$
1,237

 
$
1,718

Long-term debt due currently
$
47

 
$
669

 
$
417

 
$
385

 
$
513

___________
(a)
Fixed charges exceeded earnings (see Exhibit 12(a)) by $3.217 billion, $2.531 billion, $10.469 billion and $2.034 billion for the years ended December 31, 2011, 2010 and 2008 and the period from October 11, 2007 through December 31, 2007, respectively.
Note: Although EFH Corp. 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 that resulted in the deconsolidation of Oncor Holdings as discussed in Note 3 to Financial Statements 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 9 to Financial Statements. Results for 2011 were significantly impacted by an impairment charge related to emissions allowance intangible assets as discussed in Note 4 to Financial Statements. Results for 2010 were significantly impacted by a goodwill impairment charge as discussed in Note 5 to Financial Statements and debt extinguishment gains as discussed in Notes 8 and 10. Results for 2008 were significantly impacted by impairment charges related to goodwill, trade name and emission allowances intangible assets and natural gas-fueled generation facilities.

See Notes to Financial Statements.


51


Quarterly Information (Unaudited)
Results of operations by quarter are summarized below. In our 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
2011:
 
 
 
 
 
 
 
Operating revenues
$
1,672

 
$
1,679

 
$
2,321

 
$
1,368

Net loss
$
(362
)
 
$
(705
)
 
$
(710
)
 
$
(136
)

 
First
Quarter
 
Second
Quarter
 
Third
Quarter (b)
 
Fourth
Quarter
2010:
 
 
 
 
 
 
 
Operating revenues
$
1,999

 
$
1,993

 
$
2,607

 
$
1,636

Net income (loss)
$
355

 
$
(426
)
 
$
(2,902
)
 
$
161

___________
(a)
Net loss includes the effect of an impairment charge related to emissions allowance intangible assets (see Note 4 to Financial Statements).
(b)
Net loss includes the effect of a goodwill impairment charge (see Note 5 to Financial Statements).


52


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

The following discussion and analysis of our financial condition and results of operations for the fiscal years ended December 31, 2011, 2010 and 2009 should be read in conjunction with Selected Financial Data and our audited consolidated financial statements and the notes to those statements. Unless otherwise noted, disclosures in the following paragraphs related to hedged or estimated generation output and commodity price sensitivities reflect the expected effects on our operations of the currently governing CAIR. See Items 1 and 2, "Environmental Regulations and Related Considerations" for discussion of the CSAPR, including the judicial stay of the CSAPR, related litigation and the EPA's revisions.

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

Business

EFH Corp., a Texas corporation, is a Dallas-based holding company with operations consisting principally of our TCEH and Oncor subsidiaries. EFH Corp. is a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. EFCH and its direct subsidiary, TCEH, are wholly-owned. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. EFIH is wholly-owned and indirectly holds an approximately 80% equity interest in Oncor. Oncor is engaged in regulated electricity transmission and distribution operations in Texas. Oncor provides distribution services to REPs, including subsidiaries of TCEH, which sell electricity to residential, business and other consumers. Various "ring-fencing" measures have been taken to enhance the credit quality of Oncor. See Notes 1 and 3 to Financial Statements for discussion of the material features of these "ring-fencing" measures and the reporting of our investment in Oncor (and its majority owner, Oncor Holdings) as an equity method investment effective January 1, 2010.

Operating Segments

We have aligned and report our business activities as two operating segments: the Competitive Electric segment and the Regulated Delivery segment. The Competitive Electric segment consists largely of TCEH. The Regulated Delivery segment consists largely of our investment in Oncor . See Notes 1 and 3 to Financial Statements for discussion of the deconsolidation of Oncor and its parent, Oncor Holdings, effective in 2010.

See Note 21 to Financial Statements for further information regarding reportable business segments.

Significant Activities and Events

Natural Gas Prices and Natural Gas Price Hedging Program TCEH has a natural gas price 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, 2011, has effectively sold forward approximately 700 million MMBtu of natural gas (equivalent to the natural gas exposure of approximately 82,000 GWh at an assumed 8.5 market heat rate) at weighted average annual hedge prices ranging from $7.19 per MMBtu to $7.80 per MMBtu.

These transactions, together with forward power sales, have effectively hedged an estimated 86%, 58% and 31% of the price exposure, on a natural gas equivalent basis, related to TCEH's expected generation output for 2012, 2013 and 2014, respectively, (assuming an 8.5 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will generally move with prices of natural gas, which is expected to be the marginal fuel for the purpose of setting electricity prices generally 70% to 90% of the time in the ERCOT market. If the relationship changes in the future, the cash flows targeted under the natural gas price hedging program may not be achieved.

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 22% of the positions in the natural gas price hedging program as of December 31, 2011, 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 natural gas price hedging program.

53


The following table summarizes the natural gas positions in the hedging program as of December 31, 2011:
 
Measure
 
2012
 
2013
 
2014
 
Total
Natural gas hedge volumes (a)
mm MMBtu
 
~294
 
~254
 
~149
 
~697

Weighted average hedge price (b)
$/MMBtu
 
~7.36
 
~7.19
 
~7.80
 

Weighted average market price (c)
$/MMBtu
 
~3.24
 
~3.94
 
~4.34
 

Realization of hedge gains (d)
$ billions
 
~$1.7
 
~$0.9
 
~$0.5
 
~$3.1

___________
(a)
Where collars are reflected, the volumes are based on the notional position of the derivatives to represent protection against downward price movements. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 137 million MMBtu in 2014.
(b)
Weighted average hedge prices are based on NYMEX Henry Hub prices of forward natural gas sales positions in the natural gas price hedging program (excluding the impact of offsetting purchases for rebalancing). Where collars are reflected, sales price represents the collar floor price.
(c)
Based on NYMEX Henry Hub prices.
(d)
Based on cumulative unrealized mark-to-market gain as of December 31, 2011.

Changes in the fair value of the instruments in the natural gas price 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 natural gas price hedging program as of December 31, 2011, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $700 million in pretax unrealized mark-to-market gains or losses.

The natural gas price hedging program has resulted in reported net gains as follows:
 
Year Ended December 31,
 
2011
 
2010
 
2009
Realized net gain
$
1,265

 
$
1,151

 
$
752

Unrealized net gain (loss) including reversals of previously recorded amounts related to positions settled
(19
)
 
1,165

 
1,107

Total
$
1,246

 
$
2,316

 
$
1,859


The cumulative unrealized mark-to-market net gain related to positions in the natural gas price hedging program totaled $3.124 billion and $3.143 billion as of December 31, 2011 and 2010, respectively.

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 natural gas price hedging program reflects declining forward market natural gas prices. Forward natural gas prices have generally trended downward since mid-2008. While the natural gas price hedging program is designed to mitigate the effect on earnings of low wholesale electricity prices, depressed forward natural gas prices are challenging to the long-term profitability of our generation assets. Specifically, these lower natural gas prices and their effect in ERCOT on wholesale electricity prices could have a material impact on the overall profitability of our generation assets for periods in which we have less significant natural gas hedge positions (i.e., beginning in 2014).

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

As of December 31, 2011, approximately 90% of the natural gas price 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.

54


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, we recorded a $4.1 billion noncash goodwill impairment charge (which was not deductible for income tax purposes) related to the Competitive Electric segment. The write-off reflected the estimated effect of lower wholesale power prices on the enterprise value of the Competitive Electric segment, driven by the sustained decline in forward natural gas prices as discussed above. Recorded goodwill related to the Competitive Electric segment totaled $6.2 billion as of December 31, 2011.

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

See Note 5 to Financial Statements and "Application of Critical Accounting Policies" below for more information on goodwill impairment testing and charges.

Liability Management Program As of December 31, 2011, EFH Corp. and its consolidated subsidiaries had $36.0 billion principal amount of long-term debt outstanding. In October 2009, we implemented a liability management program designed to reduce debt and extend debt maturities through debt exchanges, repurchases and extensions. Activities under the liability management program do not include debt issued by Oncor or its subsidiaries.

Amendments to the TCEH Senior Secured Facilities completed in April 2011 resulted in the extension of $16.4 billion in loan maturities under the TCEH Term Loan Facilities and the TCEH Letter of Credit Facility from October 2014 to October 2017 and $1.4 billion of commitments under the TCEH Revolving Credit Facility from October 2013 to October 2016.

Other liability management activities from inception of the program in October 2009 through December 2011 include debt exchange, issuance and repurchase activities as follows (except where noted, debt amounts are principal amounts):
 
 
Since Inception
Security
 
Debt
Acquired
 
Debt Issued/
Cash Paid
EFH Corp 10.875% Notes due 2017
 
$
1,804

 
$

EFH Corp. Toggle Notes due 2017
 
2,661

 
53

EFH Corp. 5.55% Series P Senior Notes due 2014
 
674

 

EFH Corp. 6.50% Series Q Senior Notes due 2024
 
10

 

EFH Corp. 6.55% Series R Senior Notes due 2034
 
6

 

TCEH 10.25% Notes due 2015
 
1,875

 

TCEH Toggle Notes due 2016
 
751

 

TCEH Senior Secured Facilities due 2013 and 2014
 
1,623

 

EFH Corp. and EFIH 9.75% Notes due 2019
 

 
256

EFH Corp 10% Notes due 2020
 

 
561

EFIH 11% Notes due 2021
 

 
406

EFIH 10% Notes due 2020
 

 
2,180

TCEH 15% Notes due 2021
 

 
1,221

TCEH 11.5% Notes due 2020 (a)
 

 
1,604

Cash paid, including use of proceeds from debt issuances in 2010 (b)
 

 
1,062

Total
 
$
9,404

 
$
7,343

___________
(a)
Excludes from the $1.750 billion principal amount $12 million in debt discount and $134 million in proceeds used for transaction costs related to the issuance of these notes and the amendment and extension of the TCEH Senior Secured Facilities. All other proceeds were used to repay borrowings under the TCEH Senior Secured Facilities, and the remaining transaction costs were funded with cash on hand.
(b)
Includes $100 million of the proceeds from the January 2010 issuance of $500 million principal amount of EFH Corp. 10% Notes due 2020 and $290 million of the proceeds from the October 2010 issuance of $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021. The total $390 million of proceeds was used to repurchase debt.


55


Since inception, the transactions in the liability management program resulted in the capture of $2 billion of debt discount and the extension of approximately $23.5 billion of debt maturities to 2017-2021.

Liability management program activities in 2011 included the amendment and extension of the TCEH Senior Secured Facilities discussed above, as well as $2.143 billion principal amount of debt acquired and $2.209 billion principal amount of debt issued. In February 2012, EFIH and EFIH Finance issued $800 million principal amount of 11.750% Senior Secured Second Lien Notes due 2022. The net proceeds will be used for general corporate purposes, including the payment of a $650 million dividend to EFH Corp., which was used to repay a portion of the demand notes payable by EFH Corp. to TCEH. The balance of the demand notes payable totaled approximately $960 million at February 15, 2012, reflecting the repayment. Also see "Key Risks and Challenges – Substantial Leverage, Uncertain Financial Markets and Liquidity Risk" and Note 10 to Financial Statements.

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. We are fully certified to participate in both the "day-ahead" and "real-time markets." Additionally, all of our operational generation assets and our qualified scheduling entities are certified and operate in the nodal market. Since the opening of the nodal market, the amount of letters of credit posted with ERCOT to support our market participation has fluctuated between $125 million and $425 million based upon weekly settlement activity, and as of December 31, 2011, totaled $170 million.

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 our 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 (and the associated volumes) in 2011 were materially less than amounts reported in prior periods.


56


TCEH Interest Rate Swap Transactions — As reflected in the table below, as of December 31, 2011, TCEH has entered into the following series of interest rate swap transactions that effectively fix the interest rates at between 5.5% and 9.3%.
Fixed Rates
 
Expiration Dates
 
Notional Amount
5.5% — 9.3%
 
February 2012 through October 2014
 
$18.65 billion (a)
6.8% — 9.0%
 
October 2015 through October 2017
 
$12.60 billion (b)
___________
(a)
Includes swaps entered into in 2011 related to an aggregate $5.45 billion principal amount of debt growing to $10.58 billion over time, generally as existing swaps expire. Swaps related to an aggregate $2.60 billion principal amount of debt expired or were terminated in 2011. Taking into consideration these swap transactions, as of December 31, 2011, 2% of our long-term debt portfolio is exposed to variable interest rate risk to October 2014.
(b)
These swaps were all entered into in 2011 and are effective from October 2014 through October 2017. The swaps include $3 billion that expires in October 2015 and the remainder in October 2017.

We may enter into additional interest rate hedges from time to time.

TCEH has also entered into interest rate basis swap transactions that further reduce the fixed (through swaps) borrowing costs. Basis swaps in effect at December 31, 2011 related to an aggregate of $17.75 billion principal amount of senior secured debt maturing from 2012 through 2014, an increase of $2.55 billion from December 31, 2010 reflecting new and expired swaps. A forward-starting basis swap was entered into in 2011 related to an aggregate $1.42 billion principal amount of senior secured debt effective for a 21-month period beginning February 2012.

The interest rate swaps have resulted in net losses reported in interest expense and related charges as follows:
 
Year Ended December 31,
 
2011
 
2010
 
2009
Realized net loss
$
(684
)
 
$
(673
)
 
$
(684
)
Unrealized net gain (loss)
(812
)
 
(207
)
 
696

Total
$
(1,496
)
 
$
(880
)
 
$
12


The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $2.231 billion and $1.419 billion as of December 31, 2011 and 2010, respectively, of which $76 million and $105 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. For example, as of December 31, 2011, a one percent change in interest rates would result in an increase or decrease of approximately $900 million in our cumulative unrealized mark-to-market net liability. See discussion in Note 10 to Financial Statements regarding interest rate swap transactions.

Construction of New Lignite-Fueled Generation Units — In 2010, TCEH completed a program to construct three lignite-fueled generation units (2 units at the Oak Grove plant site and 1 unit at the Sandow plant site) 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. We began depreciating the units and recognizing revenues and fuel costs for accounting purposes in those respective periods. Aggregate cash capital expenditures for these three units 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.

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, recent and anticipated EPA actions and various other environmental matters and their effects on the company.


57


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

As of December 31, 2011, Oncor had installed 2,302,000 advanced digital meters, including 788,000 in 2011. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $518 million as of December 31, 2011, including $158 million in 2011. Oncor expects to complete installations of the remaining approximately 700,000 advanced meters by the end of 2012.

Oncor Rate Review Filed with the PUCT — In January 2011, Oncor filed for a rate review with the PUCT and 203 cities based on a test year ended June 30, 2010. In August 2011 the PUCT issued a final order in the rate review. The rate review as approved includes an approximate $137 million base rate increase and additional provisions to address certain expenses. Approximately $93 million of the increase became effective July 1, 2011, and the remainder became effective January 1, 2012. The rate review did not change Oncor's authorized regulatory capital structure of 60% debt and 40% equity or its authorized return on equity of 10.25%. See "Regulatory Matters" below for further discussion.

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


58


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 effect on our results of operations, liquidity or financial condition. Also see Item 1A "Risk Factors."

Substantial Leverage, Uncertain Financial Markets and Liquidity Risk

Our substantial leverage, resulting in large part from debt incurred to finance the Merger, and the covenants contained in our debt agreements require significant cash flows to be dedicated to interest and principal payments and could adversely affect our ability to raise additional capital to fund operations, limit our ability to react to changes in the economy, our industry (including environmental regulations) or our business. Principal amounts of short-term borrowings and long-term debt, including amounts due currently, totaled $36.7 billion as of December 31, 2011, and cash interest payments in 2011 totaled $3 billion.

Significant amounts of our long-term debt mature in the next few years, including approximate principal amounts of $120 million in 2012-2013, $4.3 billion in 2014 and $3.3 billion in 2015. A substantial amount of our debt is comprised of debt incurred under the TCEH Senior Secured Facilities. In April 2011, we secured an extension of the maturity date of approximately $16.4 billion principle amount of debt under these facilities to 2017. Notwithstanding the extension, the maturity could be reset to an earlier date under a "springing maturity" provision if, as of a defined date, certain amounts of TCEH unsecured debt maturing prior to 2017 are not refinanced and TCEH's debt to Adjusted EBITDA ratio exceeds 6.00 to 1.00 (see Note 10 to Financial Statements).

While we believe our cash on hand and cash flow from operations combined with availability under existing credit facilities provide sufficient liquidity to fund current and projected expenses and capital requirements for 2012, there can be no assurance that counterparties to our credit facility and hedging arrangements will perform as expected and meet their obligations to us. Failure of such counterparties to meet their obligations or substantial changes in financial markets, the economy, regulatory requirements, our industry or our operations could result in constraints in our 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 and continued market and regulatory uncertainty, there has been a reduction of available counterparties for our hedging and trading activities, particularly for longer-dated transactions, which could impact our ability to hedge our commodity price and interest rate exposure to desired levels at reasonable costs. See discussion of credit risk in Item 7A, "Quantitative and Qualitative Disclosures About Market Risk," discussion of available liquidity and liquidity effects of the natural gas price hedging program in "Financial Condition - Liquidity and Capital Resources" and discussion of potential impacts of legislative rulemakings on the OTC derivatives market below in "Financial Services Reform Legislation."

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

Further, a continuation, or further decline, of current forward natural gas prices could result in further declines in the values of TCEH's nuclear and lignite/coal-fueled generation assets and limit or hinder TCEH's ability to hedge its wholesale electricity revenues at sufficient price levels to support its significant interest payments and debt maturities, which could adversely impact TCEH's ability to obtain additional liquidity and refinance and/or extend the maturities of its outstanding debt. See discussion above under "Significant Activities and Events - Natural Gas Prices and Natural Gas Price Hedging Program."

We are focused on improving the balance sheet and expect to opportunistically look for ways to reduce the amount, and extend the maturity, of our outstanding debt and maintain adequate liquidity. Progress to date on this initiative includes the debt extensions, exchanges, issuances and repurchases completed in 2009 through 2011, which resulted in the extension of approximately $23.5 billion of debt maturities to 2017-2021, and the 2012 issuance of $800 million principal amount of 11.750% Senior Secured Second Lien Notes due 2022 in 2012. We have also hedged a substantial portion of variable rate debt exposure through 2017 using interest rate swaps. See "Significant Activities and Events - Liability Management Program" and Note 10 to Financial Statements.


59


Natural Gas Price and Market Heat Rate Exposure

Wholesale electricity prices in the ERCOT market have historically moved with the price of natural gas because marginal demand for electricity supply is generally met with natural gas-fueled generation facilities. The price of natural gas has fluctuated due to changes in industrial demand, supply availability and other economic and market factors, and such prices have historically been volatile. As shown in the table below, forward natural gas prices have been declining, reflecting discovery and increased drilling of shale gas deposits combined with lingering demand weakness associated with the economic recession.

 
Forward Market Prices for Calendar Year ($/MMBtu) (a)
Date
2012
 
2013
 
2014
 
2015
 
2016
December 31, 2008
$
7.23

 
$
7.15

 
$
7.15

 
$
7.21

 
$
7.30

March 31, 2009
$
6.96

 
$
7.11

 
$
7.18

 
$
7.25

 
$
7.33

June 30, 2009
$
7.16

 
$
7.30

 
$
7.43

 
$
7.57

 
$
7.71

September 30, 2009
$
7.00

 
$
7.06

 
$
7.17

 
$
7.31

 
$
7.43

December 31, 2009
$
6.53

 
$
6.67

 
$
6.84

 
$
7.05

 
$
7.24

March 31, 2010
$
5.79

 
$
6.07

 
$
6.36

 
$
6.68

 
$
7.00

June 30, 2010
$
5.68

 
$
5.89

 
$
6.10

 
$
6.37

 
$
6.68

September 30, 2010
$
5.07

 
$
5.29

 
$
5.42

 
$
5.60

 
$
5.76

December 31, 2010
$
5.08

 
$
5.33

 
$
5.49

 
$
5.64

 
$
5.79

March 31, 2011
$
5.06

 
$
5.41

 
$
5.73

 
$
6.08

 
$
6.41

June 30, 2011
$
4.84

 
$
5.16

 
$
5.42

 
$
5.70

 
$
5.98

September 30, 2011
$
4.24

 
$
4.80

 
$
5.13

 
$
5.39

 
$
5.61

December 31, 2011
$
3.24

 
$
3.94

 
$
4.34

 
$
4.60

 
$
4.85

___________
(a)
Based on NYMEX Henry Hub prices.

In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating electricity from our nuclear and lignite/coal-fueled facilities. All other factors being equal, these nuclear and lignite/coal-fueled generation assets, which provided the substantial majority of supply volumes in 2011, 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.

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 generation resource availability and the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity. While market heat rates have generally increased as natural gas prices have declined, wholesale electricity prices have declined due to the greater effect of falling natural gas prices.

Our 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 in ERCOT. Increased wind generation capacity could result in lower market heat rates. We expect that decreases in market heat rates would decrease the value of our generation assets because lower market heat rates generally result in lower wholesale electricity prices, and vice versa.

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

Our approach to managing 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.


60


As discussed above in "Significant Activities and Events," we have implemented a natural gas price hedging program to mitigate the risk of lower wholesale electricity prices due to declines in natural gas prices. While current and forward natural gas prices are currently depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward power sales. As of December 31, 2011, we have no significant hedges beyond 2014.

We mitigate market heat rate risk through retail and wholesale electricity sales contracts and shorter-term heat rate hedging transactions. We evaluate opportunities to mitigate market heat rate risk over extended periods through longer-term electricity sales contracts where practical considering pricing, credit, liquidity and related factors.

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, 2011, which for natural gas reflects estimates of electricity generation less amounts hedged through the natural gas price hedging program and amounts under existing wholesale and retail sales contracts. On a rolling basis, generally twelve-months, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.
 
Balance 2012 (a)
 
2013
 
2014
 
2015
 
2016
$1.00/MMBtu change in gas price (b)
$ ~75
 
$ ~220
 
$ ~365
 
$ ~530
 
$ ~525
0.1/MMBtu/MWh change in market heat rate (c)
$ ~10
 
$ ~30
 
$ ~35
 
$ ~40
 
$ ~40
$1.00/gallon change in diesel fuel price
$ ~10
 
$ ~45
 
$ ~45
 
$ ~45
 
$ ~45
___________
(a)
Balance of 2012 is from February 1, 2012 through December 31, 2012.
(b)
Assumes conversion of electricity positions based on an approximate 8.5 market heat rate with natural gas generally being on the margin 70% to 90% of the time in the ERCOT market (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, 2011.

61



On an ongoing basis, we will continue monitoring our overall commodity risks and seek to balance our portfolio based on our desired level of exposure to natural gas prices and market heat rates and potential changes to our operational forecasts of overall generation and consumption (which is also subject to volatility resulting from customer churn, weather, economic and other factors) in our businesses. 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.

New and Changing Environmental Regulations

We are subject to various environmental laws and regulations related to SO2, NOx and mercury as well as other emissions that impact air and water quality. We believe we are in compliance with all current laws and regulations, but regulatory authorities have recently passed new rules, such as the EPA's CSAPR and MATS, which could require material capital expenditures if the rules take effect, and authorities continue to evaluate existing requirements and consider proposals for further rules changes. If we make any major modifications to our power generation facilities, we 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 11 to Financial Statements for discussion of "Litigation Related to Generation Facilities," "Regulatory Reviews" and "Environmental Contingencies." and Items 1 and 2 "Business and Properties – Environmental Regulations and Related Considerations.")

We also continue 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 our generation portfolio consists of lignite/coal-fueled generation facilities, our results of operations, liquidity or financial condition could be materially 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 us either incurring increased material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with a mandatory cap-and-trade emissions reduction program. See further discussion under Items 1 and 2, "Business and Properties – Environmental Regulations and Related Considerations."


62


Competitive Retail Markets and Customer Retention

Competitive retail activity in Texas has resulted in retail customer churn. Our total retail customer counts declined 9% in 2011, 6% in 2010 and 3% in 2009. Based upon 2011 results discussed below in "Results of Operations – Competitive Electric Segment," a 1% decline in residential customers would result in a decline in annual revenues of approximately $35 million. In responding to the competitive landscape in the ERCOT marketplace, we are focusing on the following key initiatives:

Maintaining competitive pricing initiatives 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 has completed over 60% of its planned $100 million investment 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.

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.

Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives market. The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that we use to hedge risks associated with commodity and interest rate exposure) to be cleared by a derivatives clearing organization. However, 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. We are evaluating whether or not the type of asset-backed OTC derivatives that we use 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 we were required to post cash collateral on our swap transactions with swap dealers, our liquidity would likely be materially impacted, and our ability to enter into OTC derivatives to hedge our commodity and interest rate risks would be significantly limited.

We cannot predict the outcome of the rulemakings to implement the OTC derivative market provisions of the Financial Reform Act. These rulemakings could negatively affect our ability to hedge our commodity and interest rate risks. Accordingly, we (and other market participants) continue to closely monitor the rulemakings and any other potential legislative and regulatory changes and work with regulators and legislators. We have provided them information on our operations, the types of transactions in which we engage, our concerns regarding potential regulatory impacts, market characteristics and related matters.


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Exposures Related to Nuclear Asset Outages

Our nuclear assets are comprised of two generation units at the Comanche Peak plant site, each with an installed nameplate capacity of 1,150 MW. These units represent approximately 15% of our total generation capacity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage, the unfavorable impact to pretax earnings is estimated (based upon market prices as of December 31, 2011) to be approximately $2 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 11 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 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 units as a precautionary measure.


64


We participate 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). We also apply the knowledge gained by continuing to invest in technology, processes and services to improve our operations and detect, mitigate and protect our 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.

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 retail 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, natural gas prices rose substantially in 2007 and part of 2008 before falling in the second half of 2008 through 2011. 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 to provide lower or more predictable prices. Sustained low energy prices also create a risk of such intervention if, in an effort to incent investment to provide sufficient generation resources to be available to meet future demand, regulators or legislators take actions that impact the competitive markets.

We believe that competitive markets result in a broad range of innovative pricing and service alternatives to consumers and ultimately the most efficient use of resources and 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 our natural gas price hedging program. (Also see "Regulatory Matters – Sunset Review.") We continue to closely monitor any potential legislative and regulatory changes and work with legislators and regulators, providing them information on the market and related matters.

Oncor's Ring-Fencing and Credit Risk

Our investment in Oncor, which represents approximately 80% of its membership interests, is a significant value driver of our overall business. Oncor's access to capital markets and cost of debt could be directly affected by its credit ratings. Any adverse action with respect to Oncor's credit ratings would generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease. Oncor's credit ratings are currently substantially higher than those of the Texas Holdings Group. If credit rating agencies were to change their views of Oncor's independence from any member of the Texas Holdings Group, Oncor's credit ratings would likely decline. We believe these risks are substantially mitigated by the significant ring-fencing measures implemented by EFH Corp. and Oncor as described in Note 1 to Financial Statements.


65


Declining Reserve Margins and Weather Extremes

Planning reserve margin is the difference between system generation capability and anticipated peak load. As reflected in the table below, ERCOT is projecting declining reserve margins in the ERCOT market such that by 2014, the margin will be substantially below ERCOT's minimum reserve planning criterion of 13.75%. Weather extremes exacerbate the risks of inadequate reserve margins.
 
2012
 
2013
 
2014
 
2015
 
2016
Firm load forecast (MW)
64,618

 
65,428

 
68,174

 
71,457

 
73,713

Resources forecast (MW)
73,574

 
73,327

 
73,383

 
73,992

 
76,833

Reserve margin (a)
13.86
%
 
12.07
%
 
7.64
%
 
3.55
%
 
4.23
%
___________
(a)
Source: ERCOT's "Report on the Capacity, Demand, and Reserves in the ERCOT Region - December 2011." The 2012 resource forecast and reserve margin reflect an update presented in the January 17, 2012 ERCOT Board of Directors meeting that includes our Monticello Units 1 and 2 due to the stay of the CSAPR, which is discussed in Items 1 and 2, "Business and Properties - Environmental Regulations and Related Considerations." Reserve margin (planning) = (Resources forecast - Firm load forecast) / Firm load forecast.

We and the ERCOT market broadly experienced the effects of weather extremes in 2011. Severe cold weather in North Texas impacted the availability of generation capacity in ERCOT, including certain of our generation units, resulting in electricity outages and reduced customer satisfaction, as well as loss of revenues and higher costs in our competitive business as we worked to bring our units back on line. The unusually hot 2011 summer in Texas drove higher electricity demand that resulted in wholesale electricity price spikes and requests to consumers to conserve energy during peak load periods, while increasing stress on generation and other electricity grid assets. Drought that often accompanies hot weather extremes reduces cooling water levels at our generation facilities and can ultimately result in reduced output. Heavy rains present other challenges as flooding in other states can halt rail transportation of coal, and local flooding can reduce our lignite mining capabilities, resulting in fuel shortages and reduced generation.

While there can be no assurance that we can fully mitigate the risks of severe weather events, we have emergency preparedness, business continuity and regulatory compliance policies and procedures that are continuously reviewed and updated to address these risks. Further, we have initiatives in place to improve monitoring of generation plant equipment maintenance and readiness to increase system reliability and help ensure generation availability. We are actively focused on implementing the learnings from the winter and summer peaks of 2011 and are developing plans to assure the highest possible delivery of generation during critical periods, delivering demand side management responses and assuring we utilize our smart grid and advanced meter technology to implement ERCOT mandated rotating outages to noncritical customers. We continue to work with ERCOT and other market participants to develop policies and protocols that provide appropriate pricing signals that encourage the development of new generation to meet growing demand in the ERCOT market.

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Cyber Security and Infrastructure Protection Risk

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

We participate 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. We also apply the knowledge gained by continuing to invest in technology, processes and services to detect, mitigate and protect our 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

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

Impairment of Goodwill and Other Long-Lived Assets

We evaluate 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. For our nuclear and lignite/coal-fueled generation assets, another possible indication would be an expected long-term decline in natural gas prices and/or market heat rates. We evaluate investments in unconsolidated subsidiaries for impairment when factors indicate that a decrease in the value of the investment has occurred that is not temporary. Indications of a loss in value might include a series of operating losses of the investee or a fair value of the investment that is less than its carrying amount. 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, group of assets or investment in unconsolidated subsidiary. Further, the unique nature of our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual plants that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing.

Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually (we have selected December 1) or whenever events or changes in circumstances indicate an impairment may exist, such as the triggers to evaluate impairments to long-lived assets discussed above. As required by accounting guidance related to goodwill and other intangible assets, we have allocated goodwill to our reporting units, which are our two segments: Competitive Electric and Regulated Delivery, and goodwill impairment testing is performed at the reporting unit level. (See Notes 1 and 3 to Financial Statements for discussion of the deconsolidation of Oncor Holdings as of January 1, 2010, which resulted in a reduction in reported goodwill for the amount related to the Regulated Delivery segment, and see above for discussion of impairment testing for equity-method investments such as Oncor Holdings.) 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. We use a combination of fair value inputs to estimate enterprise values of our reporting units: internal discounted cash flow analyses (income approach), and comparable company values taking into consideration 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, the effects of environmental rules, 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 value inputs in developing the best estimate of enterprise value.


68


Since the Merger, we have recorded goodwill impairment charges totaling $13.050 billion; including $4.1 billion recorded in 2010 and $8.950 billion (including $860 million related to the Regulated Delivery segment) recorded largely in 2008. The total impairment charges represent approximately 60% of the goodwill balance resulting from purchase accounting for the Merger. The impairment in 2010 reflected the estimated effect of lower wholesale power prices in ERCOT on the enterprise value of the Competitive Electric segment, 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.

See Note 5 to Financial Statements for additional discussion.

Derivative Instruments and Mark-to-Market Accounting

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

Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. We estimate fair value as described in Note 14 to Financial Statements and discussed under "Fair Value Measurements" below.

Accounting standards related to derivative instruments and hedging activities allow for "normal" purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. "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 reclassified to net income in the period that the hedged transactions are recognized in net income. Although as of December 31, 2011, we do not have any derivatives designated as cash flow or fair value hedges, we continually assess 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 natural gas price 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 natural gas price hedging program and interest rate swap transactions under "Business – Significant Activities and Events."


69


The following tables provide the effects on both the statements of consolidated income (loss) and comprehensive income (loss) of accounting for those derivative instruments (both commodity-related and interest rate swaps) that we have determined to be subject to fair value measurement under accounting standards related to derivative instruments. (Excludes the effects related to Oncor since its deconsolidation effective January 1, 2010).
 
Year Ended December 31,
 
2011
 
2010
 
2009
Amounts recognized in net income or net loss (after-tax):
 
 
 
 
 
Unrealized net gains on positions marked-to-market in net income
$
205

 
$
1,257

 
$
1,573

Unrealized net losses representing reversals of previously recognized fair values of positions settled in the period
(696
)
 
(606
)
 
(332
)
Unrealized gain on termination of a long-term power sales contract

 
75

 

Reclassifications of net losses on cash flow hedge positions from other comprehensive income
(19
)
 
(59
)
 
(130
)
Total net gain (loss) recognized
$
(510
)
 
$
667

 
$
1,111

Amounts recognized in other comprehensive income or loss (after-tax):
 
 
 
 
 
Net losses in fair value of positions accounted for as cash flow hedges
$

 
$

 
$
(20
)
Reclassifications of net losses on cash flow hedge positions to net income
19

 
59

 
130

Total net gain recognized
$
19

 
$
59

 
$
110


The effect of mark-to-market and hedge accounting for derivatives on the balance sheet is as follows:
 
December 31,
 
2011
 
2010
Commodity contract assets
$
4,435

 
$
4,705

Commodity contract liabilities
$
(1,245
)
 
$
(1,608
)
Interest rate swap assets
$
142

 
$
98

Interest rate swap liabilities
$
(2,397
)
 
$
(1,544
)
Net accumulated other comprehensive loss included in shareholders' equity (amounts after tax)
$
(50
)
 
$
(69
)

We report derivative assets and liabilities in the balance sheet without taking into consideration netting arrangements we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the balance sheet. See Note 16 to Financial Statements.

Fair Value Measurements

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

Under the fair value hierarchy, Level 1 and Level 2 valuations generally apply to our commodity-related contracts for natural gas, electricity and fuel, including coal and uranium, 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.

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Examples of Level 2 valuation inputs utilized include over-the-counter broker quotes and quoted prices for similar assets or liabilities that are corroborated by correlation or through statistical relationships between different price curves. For example, certain physical power derivatives are executed for a particular location at specific time periods that might not have active markets; however, an active market might exist for such derivatives for a different time period at the same location. We utilize correlation techniques to compare prices for inputs at both time periods to provide a basis to value the non-active derivative. (See Note 14 to Financial Statements for additional discussion of how broker quotes are utilized.)

Level 3 valuations generally apply to congestion revenue rights, options to purchase or sell power and our more complex long-term power purchases and sales agreements, including longer term wind power purchase contracts. 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. We use the most meaningful information available from the market, combined with our own internally developed valuation methodologies, to develop our best estimate of fair value. The determination of fair value for Level 3 assets and liabilities requires significant management judgment and estimation.

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

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

Level 3 assets totaled $124 million and $401 million as of December 31, 2011 and 2010, respectively, and represented approximately 2% and 8%, respectively, of the assets measured at fair value, or less than 1% of total assets in both years. Level 3 liabilities totaled $71 million and $59 million as of December 31, 2011 and 2010, respectively, and represented approximately 2% of the liabilities measured at fair value, or less than 1% of total liabilities in both years.

Valuations of several of our 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, 2011 and 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 $21 million change in net Level 3 assets. See Note 14 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, 2011, 2010 and 2009.

Variable Interest Entities

A variable interest entity (VIE) is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. 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 and resulted in the deconsolidation of Oncor Holdings, which holds an approximate 80% interest in Oncor. In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationships among the interest holders of the VIE and the rights granted to the interest holders of the VIE to determine whether we have the right or obligation to absorb profit and loss from the VIE and the power to direct the significant activities of the VIE. See Notes 2 and 3 to Financial Statements for our analysis of the Oncor relationship and information regarding our consolidated variable interest entities.


71


Revenue Recognition

Our revenue includes an estimate for unbilled revenue that represents estimated daily kWh consumption after the meter read date to the end of the period multiplied by the applicable billing rates. Estimated daily kWh usage is derived using historical kWh usage information adjusted for weather and other measurable factors affecting consumption. Calculations of unbilled revenues during certain interim periods are generally subject to more estimation variability because of seasonal changes in demand. Accrued unbilled revenues totaled $269 million, $297 million and $546 million as of December 31, 2011, 2010 and 2009, respectively.

Accounting for Contingencies

Our financial results may be affected by judgments and estimates related to loss contingencies. A significant contingency that we account for is the loss associated with uncollectible trade accounts receivable. The determination of such bad debt expense is based on factors such as historical write-off experience, aging of accounts receivable balances, changes in operating practices, regulatory rulings, general economic conditions, effects of hurricanes and other natural disasters and customers' behaviors. Changes in customer count and mix due to competitive activity and seasonal variations in amounts billed add to the complexity of the estimation process. Historical results alone are not always indicative of future results, causing management to consider potential changes in customer behavior and make judgments about the collectability of accounts receivable. Bad debt expense, the substantial majority of which relates to our competitive retail operations, totaled $56 million, $108 million and $113 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Litigation contingencies also may require significant judgment in estimating amounts to accrue. We accrue liabilities for litigation contingencies when such liabilities are considered probable of occurring and the amount is reasonably estimable. No significant amounts have been accrued for such contingencies during the three-year period ended December 31, 2011. See Item 3, "Legal Proceedings" for discussion of significant litigation.

Accounting for Income Taxes

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

In 2010, we reduced our liability for uncertain tax positions by $162 million as a result of negotiations with the IRS. This reduction consisted of a $225 million reversal of accrued interest ($146 million after-tax), partially offset by a $63 million reclassification to net deferred tax liabilities. Upon conclusion of all issues contested with the IRS from that 1997 through 2002 audit, which could occur by the end of 2012, we expect to reduce the liability for uncertain tax positions by approximately $700 million with an offsetting decrease in deferred tax assets that arose largely from previous payments of alternative minimum taxes. Any cash income tax liability related to the conclusion of the 1997 through 2002 audit is expected to be immaterial. The IRS audit for the years 2003 through 2006 was concluded in June 2011. A significant number of proposed adjustments are in appeals with the IRS. The results of the audit did not affect management's assessment of issues for purposes of determining the liability for uncertain tax positions. See Notes 1, 6 and 7 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 for the Merger. 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 21 to 58 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 5 to Financial Statements for additional information.

72


Defined Benefit Pension Plans and OPEB Plans

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

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

Benefit costs are impacted by actual and actuarial estimates of 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. Actuarial assumptions are reviewed and updated annually based on current economic conditions and trends. 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,
 
2011
 
2010
 
2009
Pension costs
$
141

 
$
100

 
$
44

OPEB costs
94

 
80

 
70

Total benefit costs
$
235

 
$
180

 
$
114

Less amounts expensed by Oncor (and not consolidated)
(37
)
 
(37
)
 

Less amounts deferred principally as a regulatory asset or property by Oncor
(130
)
 
(93
)
 
(66
)
Net amounts recognized as expense
$
68

 
$
50

 
$
48

Discount rate (a)
5.50
%
 
5.90
%
 
6.90
%
___________
(a)
Discount rate for OPEB was 5.55%, 5.90% and 6.85% in 2011, 2010 and 2009, respectively.

See Note 18 to Financial Statements regarding other disclosures related to pension and OPEB obligations.

Sensitivity of these costs to changes in key assumptions is as follows:
Assumption
Increase/
(decrease) in
2011 Pension and
OPEB Costs
Discount rate – 1% increase
$
(49
)
Discount rate – 1% decrease
$
57

Expected return on assets – 1% increase
$
(24
)
Expected return on assets – 1% decrease
$
24



73


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 were materially less than amounts reported in prior periods. Effective with the nodal market implementation, if volumes delivered to our retail and wholesale customers are less than our generation volumes (as determined on a daily settlement basis), we record additional wholesale revenues. Conversely, if volumes delivered to our retail and wholesale customers exceed our generation volumes, we record 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.

Consolidated Financial Results — Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

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

In 2010, a $4.1 billion impairment of goodwill was recorded in the Competitive Electric segment as discussed in Note 5 to Financial Statements.

See Note 8 to Financial Statements for details of other income and deductions.

Interest expense and related charges increased $740 million, or 21%, to $4.294 billion in 2011. Interest paid/accrued increased $346 million to $3.027 billion driven by higher average rates reflecting debt exchanges and amendments. The balance of the increase reflected $605 million in higher unrealized mark-to-market net losses related to interest rate swaps, $58 million in higher amortization of debt issuance and amendment costs and discounts and $29 million in lower capitalized interest, partially offset by a $227 million decrease in interest accrued or paid with additional toggle notes due to debt exchanges and repurchases and $60 million in lower amortization of interest rate swap losses at dedesignation of hedge accounting.

Income tax benefit totaled $1.134 billion on a pretax loss in 2011 compared to income tax expense totaling $389 million on a pretax gain in 2010, excluding the $4.1 billion nondeductible goodwill impairment charge. The effective rate was 34.0% and 27.8% in 2011 and 2010, respectively, excluding the goodwill impairment charge. The increase in the rate was driven by a $146 million reversal in 2010 of previously accrued interest related to uncertain tax positions due to expected resolution of matters related to the 1997 through 2002 tax audit.

Equity in earnings of our Oncor Holdings unconsolidated subsidiary (net of tax) increased $9 million to $286 million in 2011 reflecting improved results at Oncor due to higher revenue rates and the effects of warmer weather, partially offset
by higher depreciation and operation and maintenance expense.

Net loss decreased $899 million to $1.913 billion in 2011.