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Filed Pursuant to Rule 424(b)(3)
Registration Nos. 333-157049, 333-157049-01 to 333-157049-02
ENERGY FUTURE HOLDINGS CORP.
SUPPLEMENT NO. 9 TO
MARKET MAKING PROSPECTUS DATED
APRIL 9, 2010
THE DATE OF THIS SUPPLEMENT IS FEBRUARY 22, 2011
On February 18, 2011, Energy Future Holdings Corp. filed the attached Annual Report on Form 10-K with
the Securities and Exchange Commission.
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2010
— OR—
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number 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 in 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 ¨ No ¨ (The registrant is not currently required to submit such files.)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ¨ | Accelerated filer | ¨ | |||
| Non-Accelerated filer | x (Do not check if a smaller reporting company) | Smaller reporting company | ¨ | |||
Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
As of February 15, 2011, there were 1,671,912,118 shares of common stock, without 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
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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 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 Form 10-K because such representation or warranty may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent the parties’ risk allocation in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes or may no longer continue to be true as of any given date.
This Form 10-K and other Securities and Exchange Commission filings of 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 companies’ 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.
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When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
| 1999 Restructuring Legislation | Texas Electric Choice Plan, the legislation that restructured the electric utility industry in Texas to provide for retail competition | |
| 2009 Form 10-K | EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2009 | |
| Adjusted EBITDA | Adjusted EBITDA means EBITDA adjusted to exclude 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 GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA in this Form 10-K (see reconciliations in Exhibit 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. | |
| baseload | Refers to the minimum constant level of electricity demand in a system, such as ERCOT, and/or to the electricity generation facilities or capacity normally expected to operate continuously throughout the year to serve such demand, such as our nuclear and lignite/coal-fueled generation units. | |
| CAIR | Clean Air Interstate Rule | |
| Capgemini | Capgemini Energy LP, a provider of business support services to EFH Corp. and its subsidiaries | |
| CATR | Clean Air Transport Rule | |
| CFTC | Commodity Futures Trading Commission | |
| CO2 | carbon dioxide | |
| Competitive Electric segment | Refers to the EFH Corp. business segment that consists principally of TCEH. | |
| CREZ | Competitive Renewable Energy Zone | |
| DOE | US Department of Energy | |
| EBITDA | Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. See the definition of Adjusted EBITDA above. | |
| 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. | |
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| 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) and EFIH’s and EFIH Finance’s 10.000% Senior Secured Notes due December 1, 2020 (EFIH 10% Notes). | |
| EPA | US Environmental Protection Agency | |
| EPC | engineering, procurement and construction | |
| ERCOT | Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas | |
| ERISA | Employee Retirement Income Security Act of 1974, as amended | |
| FASB | Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting | |
| FERC | US Federal Energy Regulatory Commission | |
| GAAP | generally accepted accounting principles | |
| GHG | greenhouse gas | |
| GWh | gigawatt-hours | |
| IRS | US Internal Revenue Service | |
| kV | kilovolts | |
| kWh | kilowatt-hours | |
| Lehman | Refers to certain subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code in 2008. | |
| LIBOR | London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market. | |
| Luminant | Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas. | |
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| market heat rate | Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors. | |
| Merger | The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007 | |
| Merger Agreement | Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp. | |
| Merger Sub | Texas Energy Future Merger Sub Corp, a Texas corporation and a wholly-owned subsidiary of Texas Holdings that was merged into EFH Corp. on October 10, 2007 | |
| MMBtu | million British thermal units | |
| Moody’s | Moody’s Investors Services, Inc. (a credit rating agency) | |
| MW | megawatts | |
| MWh | megawatt-hours | |
| NERC | North American Electric Reliability Corporation | |
| NOx | nitrogen oxide | |
| NRC | US Nuclear Regulatory Commission | |
| NYMEX | Refers to the New York Mercantile Exchange, a physical commodity futures exchange. | |
| Oncor | Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities. | |
| 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 | |
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| purchase accounting | The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill. | |
| Regulated Delivery segment | Refers to the EFH Corp. business segment that consists of the operations of Oncor. | |
| REP | retail electric provider | |
| RRC | Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas | |
| S&P | Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies Inc. (a credit rating agency) | |
| SARs | Stock Appreciation Rights | |
| SARs Plan | Refers to the Oncor Electric Delivery Company Stock Appreciation Rights Plan | |
| SEC | US Securities and Exchange Commission | |
| Securities Act | Securities Act of 1933, as amended | |
| SG&A | selling, general and administrative | |
| SO2 | sulfur dioxide | |
| Sponsor Group | Refers collectively to the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman, Sachs & Co. (See Texas Holdings below.) | |
| TCEH | Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of EFCH and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy markets activities. Its major subsidiaries include Luminant and TXU Energy. | |
| TCEH Finance | Refers to TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities. | |
| TCEH Senior Notes | Refers collectively to TCEH’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015, Series B (collectively, TCEH 10.25% Notes) and TCEH’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes). | |
| TCEH Senior Secured Facilities | Refers collectively to the TCEH Initial Term Loan Facility, TCEH Delayed Draw Term Loan Facility, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 11 to Financial Statements for details of these facilities. | |
| TCEH Senior Secured Second Lien Notes | Refers collectively to TCEH’s 15% Senior Secured Second Lien Notes due April 1, 2021 and TCEH’s 15% Senior Secured Second Lien Notes due April 1, 2021, Series B. | |
| TCEQ | Texas Commission on Environmental Quality | |
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| Texas Holdings | Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp. | |
| Texas Holdings Group | Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities. | |
| Texas Transmission | Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of its subsidiaries or any member of the Sponsor Group. | |
| TRE | Refers to Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and ERCOT protocols. | |
| TXU Energy | Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT. | |
| TXU Gas | TXU Gas Company, a former subsidiary of EFH Corp. | |
| US | United States of America | |
| VIE | variable interest entity | |
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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. TCEH is wholly-owned, and EFH Corp. holds an approximately 80% equity interest in Oncor. Immediately below is an organization chart of the key subsidiaries discussed in this report.
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.
TCEH owns or leases 15,427 MW of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas-fueled generation facilities. This capacity includes two new lignite-fueled units that achieved substantial completion (as defined in the EPC agreements for the units) in the fourth quarter 2009 and a third new lignite-fueled unit that achieved substantial completion (as defined in the EPC agreement for the unit) in the second quarter 2010. In addition, TCEH is the largest purchaser of wind-generated electricity in Texas and the fifth largest in the US. TCEH provides competitive electricity and related services to approximately two million retail electricity customers in Texas.
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Oncor is engaged in regulated electricity transmission and distribution operations in Texas that are primarily regulated by the PUCT. Oncor provides both distribution services to retail electric providers that sell electricity to consumers and transmission services to other electricity distribution companies, cooperatives and municipalities. Oncor operates the largest transmission and distribution system in Texas, delivering electricity to approximately three million homes and businesses and operating more than 118,000 miles of transmission and distribution lines. A significant portion of Oncor’s revenues represent fees for delivery services provided to TCEH. Distribution revenues from TCEH represented 36% and 38% of Oncor’s total revenues for the years ended December 31, 2010 and 2009, respectively.
EFH Corp. and Oncor have implemented certain structural and operational “ring-fencing” measures based on commitments made by Texas Holdings and Oncor to the PUCT that are intended to enhance the credit quality of Oncor. These measures serve to mitigate Oncor’s and Oncor Holdings’ credit exposure to the Texas Holdings Group and to reduce the risk that the assets and liabilities of Oncor or Oncor Holdings would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities. See Note 1 to Financial Statements for a description of the material features of these “ring-fencing” measures.
As of December 31, 2010, we had approximately 9,200 full-time employees (including approximately 3,800 at Oncor), including approximately 2,750 employees under collective bargaining agreements (including approximately 650 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 system operator of the interconnected transmission grid for those systems. ERCOT’s membership consists of approximately 300 corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, investor-owned utilities, REPs and consumers.
The ERCOT market operates under reliability standards set by the NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure adequacy and reliability of power supply across Texas’s main interconnected transmission grid. The ERCOT independent system operator is responsible for procuring energy on behalf of its members while maintaining reliable operations of the electricity supply system in the market. Its responsibilities include centralized dispatch of the power pool and ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. The ERCOT independent system operator also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.
Significant changes in the operations of the wholesale electricity market resulted from the change from a zonal to a nodal market implemented by ERCOT in December 2010. The nodal market design reflects a substantial increase in settlement price points for participants and establishes a new “day-ahead market,” operated by ERCOT, in which participants can enter into forward sales and purchases of electricity. The nodal market also establishes hub trading prices, which represent the average of node prices within geographic regions, at which participants can hedge and trade power through bilateral transactions. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events – Wholesale Market Design – Nodal Market” for additional discussion of the ERCOT nodal market.
Oncor, along with other owners of transmission and distribution facilities in Texas, assists the ERCOT independent system operator in its operations. Oncor has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated distribution service area. Oncor participates with the ERCOT independent system operator and other ERCOT utilities in obtaining regulatory approvals and planning, designing and constructing new transmission lines in order to remove existing constraints on the ERCOT transmission grid. The transmission lines are necessary to meet reliability needs, support renewable energy production and increase bulk power transfer capability.
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The following data is derived from information published by ERCOT:
Installed generation capacity in the ERCOT market estimated for 2011 totals approximately 85,000 MW, including approximately 3,000 MW mothballed (idled) capacity, as well as more than 10,000 MW of wind, water and other resources that may not be available coincident with system need. In August 2010, ERCOT’s hourly demand peaked at a record 65,776 MW. Of ERCOT’s estimate of total available capacity for 2011, approximately 60% is natural gas-fueled generation, approximately 28% is lignite/coal and nuclear-fueled baseload generation and approximately 12% in wind and other renewable resources. In November 2010, ERCOT changed its minimum reserve margin planning criterion to 13.75% from 12.5%; the reserve margin is projected by ERCOT to be 15.94% in 2011, 15.78% in 2012, and 13.14% by 2013. Reserve margin is the difference between system generation capability and anticipated peak load.
The ERCOT market has limited interconnections to other markets in the US, which currently limits potential imports into and exports out of the ERCOT market to 1,106 MW of generation capacity (or approximately 2% of peak demand). In addition, wholesale transactions within the ERCOT market are generally not subject to regulation by the FERC.
Natural gas-fueled generation is the predominant electricity capacity resource in the ERCOT market and accounted for approximately 39% of the electricity produced in the ERCOT market in 2010. Because of the significant natural gas-fueled capacity and the ability of such facilities to more readily increase or decrease production when compared to baseload generation, marginal demand for electricity is usually met by natural gas-fueled facilities. As a result, wholesale electricity prices in ERCOT largely correlate with natural gas prices.
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 risk and providing high quality service and innovative energy products to retail and wholesale customers. |
| • | Oncor focuses on delivering electricity in a safe and reliable manner, minimizing service interruptions and investing in its transmission and distribution infrastructure to maintain its system, serve its growing customer base with a modernized grid and support renewable energy production. |
Other elements of our strategies include:
| • | Increase value from existing business lines. Our strategy focuses on striving for top quartile or better performance across our operations in terms of safety, reliability, cost and customer service. In establishing tactical objectives, we incorporate the following core operating principles: |
| • | Safety: Placing the safety of communities, customers and employees first; |
| • | Environmental Stewardship: Continuing to make strategic and operational improvements that lead to cleaner air, land and water; |
| • | Customer Focus: Delivering products and superior service to help customers more effectively manage their use of electricity; |
| • | Community Focus: Being an integral part of the communities in which we live, work and serve; |
| • | Operational Excellence: Incorporating continuous improvement and financial discipline in all aspects of the business to achieve top-tier results that maximize the value of the company for stakeholders, including operating world-class facilities that produce and deliver safe and dependable electricity at affordable prices, and |
| • | Performance-Driven Culture: Fostering a strong values- and performance-based culture designed to attract, develop and retain best-in-class talent. |
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| • | Pursue growth opportunities across business lines. Scale in our operating businesses allows us to take part in large capital investments, such as new generation projects and investments in the transmission and distribution system, with a smaller fraction of overall capital at risk and with an enhanced ability to streamline costs. We expect to also explore smaller-scale growth initiatives that are not expected to be material to our performance over the near term but can enhance our growth profile over time. Specific growth initiatives include: |
| • | Pursue generation development opportunities to help meet ERCOT’s growing electricity needs over the longer term from a diverse range of alternatives such as nuclear, renewable energy and advanced coal technologies. |
| • | Profitably increase the number of retail customers served throughout the competitive ERCOT market areas by delivering superior value through high quality customer service and innovative energy products, including leading energy efficiency initiatives and service offerings. |
| • | Invest in transmission and distribution technology upgrades, including advanced metering systems and energy efficiency initiatives, and construct new transmission and distribution facilities to meet the needs of the growing Texas market. These growth initiatives benefit from regulatory capital recovery mechanisms known as “capital trackers” that enable adequate and timely recovery of transmission and advanced metering investments through regulated rates. |
| • | Reduce the volatility of cash flows through an electricity price risk management strategy. 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. |
The strong historical correlation between natural gas prices and wholesale electricity prices in the ERCOT market provides us an opportunity to manage our exposure to variability of wholesale electricity prices. We have established a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments, and as of December 31, 2010, has effectively sold forward approximately 1.0 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 125,000 GWh at an assumed 8.0 market heat rate) for the period January 1, 2011 through December 31, 2014 at weighted average annual hedge prices ranging from $7.19 per MMBtu to $7.80 per MMBtu.
These transactions, as well as forward power sales, have effectively hedged an estimated 62% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning January 1, 2011 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will largely correlate with natural gas prices, which are expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If this correlation changes, the cash flows targeted under the long-term hedging program may not be achieved. As of December 31, 2010, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility), thereby reducing the cash and letter of credit collateral requirements for the hedging program. For additional discussion of the long-term hedging program, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” specifically sections entitled “Significant Activities and Events – Natural Gas Prices and Long-Term Hedging Program,” “Key Risks and Challenges – Natural Gas Price and Market Heat-Rate Exposure” and “Financial Condition – Liquidity and Capital Resources – Liquidity Effects of Commodity Hedging and Trading Activities.”
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| • | Strengthen balance sheet through a liability management program. In 2009, 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 $5.0 billion of maturities from 2014-2017 to 2019-2021. Activities to date have included debt exchanges, issuances and repurchases completed in 2010 and 2009 discussed below under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events – Liability Management Program” and the August 2009 amendment to the Credit Agreement governing the TCEH Senior Secured Facilities that provided additional flexibility in restructuring debt obligations. See Note 11 to Financial Statements for additional discussion of these transactions. |
Future activities under the liability management program may include the purchase of our outstanding debt for cash in open market purchases or privately negotiated transactions (including pursuant to a Section 10b-5(1) plan) or via public or private exchange or tender offers. Moreover, as part of our liability management program, we may refinance our existing debt, including the TCEH Senior Secured Credit Facilities.
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 in the pursuit of technology development opportunities that reduce our impact on the environment while balancing the need to help address the energy requirements of Texas. The Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, labor unions, customers, economic development in Texas and technology/reliability standards. In addition, we are focused on and are pursuing opportunities to reduce emissions from our existing and new lignite/coal-fueled generation units. We have voluntarily committed to reduce emissions of mercury, NOx and SO2 at our existing units. We expect to make these reductions through a combination of investment in new emission control equipment, new coal cleaning technologies and optimizing fuel blends. In addition, we expect to invest $400 million over a five-year period that began in 2008 in programs designed to encourage customer electricity demand efficiencies, representing $200 million more than amounts planned to be invested by Oncor to meet regulatory requirements. As of December 31, 2010, we invested a cumulative total of $229 million in these programs. |
Seasonality
Our revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.
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Operating Segments
We have aligned and report our business activities as two operating segments: the Competitive Electric segment (primarily represented by TCEH) and the Regulated Delivery segment (primarily represented by Oncor). See Note 23 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. However, for purposes of operational accountability, performance management and market identity, the segment operations have been grouped into Luminant, which is engaged in electricity generation and wholesale markets activities, and TXU Energy, which is engaged in retail electricity sales activities. These activities are conducted through separate legal entities.
Luminant — Luminant’s existing electricity generation fleet consists of 14 plants in Texas with total installed nameplate generating capacity as shown in the table below:
Fuel Type | Installed Nameplate Capacity (MW) | Number of Plants | Number of Units (a) | |||||||||
Nuclear | 2,300 | 1 | 2 | |||||||||
Lignite/coal | 8,017 | 5 | 12 | |||||||||
Natural gas (b)(c) | 5,110 | 8 | 26 | |||||||||
Total | 15,427 | 14 | 40 | |||||||||
| (a) | Leased units consist of six natural gas-fueled combustion turbine units totaling 390 MW of capacity. All other units are owned. |
| (b) | Includes 1,655 MW representing four units mothballed and not currently available for dispatch. See “Natural Gas-Fueled Generation Operations” below. |
| (c) | Includes 1,268 MW representing eight units currently operated for unaffiliated parties. |
The generation plants are located primarily on land owned in fee. Nuclear and lignite/coal-fueled (baseload) plants are generally scheduled to run at capacity except for periods of scheduled maintenance activities or, in the case of lignite/coal-fueled units, short-term production backdown in periods of low wholesale power prices (i.e., economic backdown). The natural gas-fueled generation units supplement the baseload generation capacity in meeting consumption in peak demand periods as production from a certain number of these units can more readily be ramped up or down as demand warrants.
Nuclear Generation Operations — Luminant operates two nuclear generation units at the Comanche Peak facility, each of which is designed for a capacity of 1,150 MW. Comanche Peak’s Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, and are generally operated at full capacity to meet the load requirements in ERCOT. Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, the refueling cycle results in the refueling of both units during the same year, which is planned for 2011 and last occurred in 2008. While one unit is undergoing a refueling outage, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance, modification and testing activities are completed that cannot be accomplished when the unit is in operation. Over the last three years the refueling outage period per unit has ranged from 19 to 26 days. The Comanche Peak facility operated at a capacity factor of 95% in 2008, reflecting refueling of both units, and 100% in both 2009 and 2010.
Luminant has contracts in place for all of its uranium, nuclear fuel conversion services and nuclear fuel enrichment services for 2011. For the period of 2012 through 2018, Luminant has contracts in place for the acquisition of approximately 65% of its uranium requirements and 51% of its nuclear fuel conversion services requirements. In addition, Luminant has contracts in place for all of its nuclear fuel enrichment services through 2013, as well as all of its nuclear fuel fabrication services through 2018. Luminant does not anticipate any significant difficulties in acquiring uranium and contracting for associated conversion services and enrichment services in the foreseeable future.
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Luminant believes its on-site used nuclear fuel storage capability is sufficient for a minimum of three years. The nuclear industry is continuing to review ways to enhance security of used-fuel storage with the NRC to fully utilize physical storage capacity. Future on-site used nuclear fuel storage capability will require the use of the industry technique of dry cask storage.
The Comanche Peak nuclear generation units have an estimated useful life of 60 years from the date of commercial operation. Therefore, assuming that Luminant receives 20-year license extensions, similar to what has been granted by the NRC to several other commercial generation reactors over the past several years, plant decommissioning activities would be scheduled to begin in 2050 for Comanche Peak Unit 1 and 2053 for Unit 2 and common facilities. Decommissioning costs will be paid from a decommissioning trust that, pursuant to state law, is funded from Oncor’s customers through an ongoing delivery surcharge. (See Note 18 to Financial Statements for discussion of the decommissioning trust fund.)
Nuclear insurance provisions are discussed in Note 12 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 generation site. In connection with the filing of the application, in January 2009, subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, Comanche Peak Nuclear Power Company (CPNPC), to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. The TCEH subsidiary owns an 88% interest in CPNPC, and a MHI subsidiary owns a 12% interest.
In March 2009, the NRC announced an official review schedule for the license application. Based on the schedule, the NRC expects to complete its review by December 2011, and it is expected that a license would be issued approximately one year later. In November 2009, CPNPC filed a comprehensive revision to the license application that updated the license application for developments occurring after the initial filing.
In 2009, the DOE announced that it had selected four applicants to proceed to the due diligence phase of its Loan Guarantee Program and to commence negotiations towards potential loan guarantees for their respective generation projects. CPNPC was not among the initial four applicants selected by the DOE; however, CPNPC continues to update the DOE on its progress, with the goal of securing a DOE loan guarantee for financing the proposed units prior to commencement of construction.
Lignite/Coal-Fueled Generation Operations — Luminant’s lignite/coal-fueled generation fleet capacity totals 8,017 MW (including three recently constructed new units) and consists of the Big Brown (2 units), Monticello (3 units), Martin Lake (3 units), Oak Grove (2 units) and Sandow (2 units) plants. These plants are generally operated at full capacity to help meet the load requirements in ERCOT, and maintenance outages are scheduled during seasonal off-peak demand periods. Over the last three years, the total annual scheduled and unscheduled outages per unit (excluding the three new units) averaged 33 days. Luminant’s lignite/coal-fueled generation fleet operated at a capacity factor of 87.6% in 2008, 86.5% in 2009 and 82.2% in 2010, which represents top quartile performance of US coal-fueled generation facilities. The 2008 performance reflects extended unplanned outages at several units, and the 2010 and 2009 performance reflects increased economic backdown of the units, reflecting short-term periods when wholesale electricity market prices were less than production costs.
Luminant recently completed the construction of three lignite-fueled generation units with a total capacity of 2,180 MW. The three units consist of one unit at a leased site that is adjacent to an existing lignite-fueled generation unit (Sandow) and two units at an owned site (Oak Grove). The Sandow unit and the first Oak Grove unit achieved substantial completion (as defined in the EPC agreements for the respective units) in the fourth quarter 2009. The second Oak Grove unit achieved substantial completion (as defined in the EPC agreement for the unit) in the second quarter 2010. Accordingly, Luminant has operational control of these units.
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Aggregate cash capital expenditures for these three units totaled approximately $3.25 billion including all construction, site preparation and mining development costs. The investment included approximately $500 million for state-of-the-art emissions controls for the three new units. Including capitalized interest and the step-up in construction work-in-process balances to fair value as a result of purchase accounting for the Merger in 2007, carrying value of the units totaled approximately $4.8 billion upon completion.
Luminant also has an environmental retrofit program under which it plans to install additional environmental control systems at its existing lignite/coal-fueled generation facilities. Capital expenditures associated with these additional environmental control systems could exceed $1.0 billion, of which $377 million was spent through 2010. Luminant has not yet completed all detailed cost and engineering studies for the additional environmental systems, and the cost estimates could change materially as it determines the details of and further evaluates the engineering and construction costs related to these investments.
Approximately 58% of the fuel used at Luminant’s lignite/coal-fueled generation plants in 2010 was supplied from lignite reserves owned in fee or leased surface-minable deposits dedicated to the Big Brown, Monticello, Martin Lake and Oak Grove plants, which were constructed adjacent to the reserves. Luminant owns in fee or has under lease an estimated 800 million tons of lignite reserves dedicated to its generation plants, including 246 million tons associated with an undivided interest in the lignite mine that provides fuel for the Sandow facility. Luminant also owns in fee or has under lease in excess of 85 million tons of reserves not currently dedicated to specific generation plants. In 2010, Luminant recovered approximately 27.5 million tons of lignite to fuel its generation plants. Luminant utilizes owned and/or leased equipment to remove the overburden and recover the lignite.
Luminant’s lignite mining operations include extensive reclamation activities that return the land to productive uses such as wildlife habitats, commercial timberland and pasture land. In 2010, Luminant reclaimed 1,729 acres of land. In addition, Luminant planted 1.2 million trees in 2010, the majority of which were part of the reclamation effort.
Luminant supplements its lignite fuel at Big Brown, Monticello and Martin Lake with western coal from the Powder River Basin in Wyoming. The coal is purchased from multiple suppliers under contracts of various lengths and is transported from the Powder River Basin to Luminant’s generation plants by railcar. Based on its current usage, Luminant believes that it has sufficient lignite reserves for the foreseeable future and has contracted more than 95% of its western coal resources and all of the related transportation through 2012.
Natural Gas-Fueled Generation Operations — Luminant’s fleet of 26 natural gas-fueled generation units totaling 5,110 MW of capacity includes 2,187 MW of currently available capacity, 1,268 MW of capacity being operated for unaffiliated third parties and 1,655 MW of capacity currently mothballed (idled). The natural gas-fueled units predominantly serve as peaking units that can be ramped up or down to balance electricity supply and demand.
Wholesale Operations — Luminant’s wholesale operations play a pivotal role in our competitive business portfolio by optimally dispatching the generation fleet, including the baseload facilities, sourcing all of TXU Energy’s electricity requirements and managing commodity price risk associated with electricity sales and generation fuel requirements.
Our electricity price exposure is managed across the complementary Luminant generation and TXU Energy retail businesses on a portfolio basis. Under this approach, Luminant’s wholesale operations manage the risks of imbalances between generation supply and sales load, as well as exposures to natural gas price movements and market heat rate changes (variations in the relationships between natural gas prices and wholesale electricity prices), through wholesale market activities that include physical purchases and sales and transacting in financial instruments.
Luminant’s wholesale operations provide TXU Energy and other retail and wholesale customers with electricity and related services to meet their demands and the operating requirements of ERCOT. In consideration of operational production and customer consumption levels that can be highly variable, as well as opportunities for long-term purchases and sales with large wholesale market participants, Luminant buys and sells electricity in short-term transactions and executes longer-term forward electricity purchase and sales agreements. Luminant is the largest purchaser of wind-generated electricity in Texas and the fifth largest in the US with more than 900 MW of existing wind power under contract.
Fuel price exposure, primarily relating to Powder River Basin coal, natural gas and fuel oil and the transportation of the fuel, is managed primarily through short- and long-term contracts for physical delivery of fuel as well as financial contracts.
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In its hedging activities, Luminant enters into contracts for the physical delivery of electricity and fuel commodities, exchange traded and “over-the-counter” financial contracts and bilateral contracts with other wholesale electricity market participants, including generators and end-use customers. A major part of these hedging activities is a long-term hedging program, described above under “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 synthesizes operational activities across the fleet and interfaces with various wholesale market channels. In addition, the wholesale operations manage the fuel procurement requirements for Luminant’s fossil fuel generation facilities.
Luminant’s wholesale operations include electricity and natural gas trading and third-party energy management activities. Natural gas transactions include direct purchases from natural gas producers, transportation agreements, storage leases and commercial retail sales. Luminant currently manages approximately 11 billion cubic feet of natural gas storage capacity.
Luminant’s wholesale operations manage exposure to wholesale commodity and credit-related risk within established transactional risk management policies, limits and controls. These policies, limits and controls have been structured so that they are practical in application and consistent with stated business objectives. Risk management processes include capturing transactions, performing and validating valuations and reporting exposures on a daily basis using risk management information systems designed to support a large transactional portfolio. A risk management forum meets regularly to ensure that business practices comply with approved transactional limits, commodities, instruments, exchanges and markets. Transactional risks are monitored to ensure limits comply with the established risk policy. Luminant has a disciplinary program to address any violations of the risk management policies and periodically reviews these policies to ensure they are responsive to changing market and business conditions.
TXU Energy — TXU Energy serves approximately two million residential and commercial retail electricity customers in Texas with approximately 62% of retail revenues in 2010 from residential customers. Texas is one of the fastest growing states in the nation with a diverse economy and, as a result, has attracted a number of competitors into the retail electricity market; consequently, competition is robust. TXU Energy, as an active participant in this competitive market, provides retail electric service to all areas of the ERCOT market now open to competition, including the Dallas/Fort Worth, Houston, Corpus Christi, and lower Rio Grande Valley areas of Texas. TXU Energy continues to market its services in Texas to add new customers and to retain its existing customers. There are approximately 120 active REPs certified to compete within the State of Texas. Based upon data published by the PUCT, as of September 30, 2010, approximately 53% of residential customers in competitive areas of ERCOT are served by REPs not affiliated with the pre-competition utility.
TXU Energy’s strategy focuses on providing its customers with high quality customer service and creating new products and services to meet customer needs; accordingly, a new customer management computer system was implemented in 2009, and other customer care enhancements are being implemented to further improve customer satisfaction. TXU Energy offers a wide range of residential products to meet various customer needs. TXU Energy is investing $100 million over the five-year period ending 2012, including a cumulative total of $39 million spent as of December 31, 2010, in energy efficiency initiatives as part of a program to offer customers a broad set of innovative energy products and services.
A subsidiary of EFH Corp. was recently certified by the Pennsylvania Public Utility Commission to sell retail electricity in Pennsylvania. While we have made no commitments to enter markets outside of Texas, we continuously monitor competitive retail markets for potential opportunities.
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Regulation —Luminant is an exempt wholesale generator under the Energy Policy Act of 2005 and is subject to the jurisdiction of the NRC with respect to its nuclear generation plant. NRC regulations govern the granting of licenses for the construction and operation of nuclear-fueled generation facilities and subject such facilities to continuing review and regulation. Luminant also holds a power marketer license from the FERC and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior and any other competition-related rules and regulations under the Federal Power Act that are administered by the FERC.
Luminant is also subject to the jurisdiction of the PUCT’s oversight of the competitive ERCOT wholesale electricity market. PUCT rules 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.
Regulated Delivery Segment
The Regulated Delivery segment consists of the operations of Oncor. Oncor is a regulated electricity transmission and distribution company that provides the service of delivering electricity safely, reliably and economically to end-use consumers through its distribution systems, as well as providing transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas. Oncor’s service territory comprises 91 counties and over 400 incorporated municipalities, including Dallas/Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler and Killeen. Oncor’s transmission and distribution assets are located principally in the north-central, eastern and western parts of Texas. Most of Oncor’s power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way as permitted by law. Oncor’s transmission and distribution rates are regulated by the PUCT.
Oncor is not a seller of electricity, nor does it purchase electricity for resale. It provides transmission services to other electricity distribution companies, cooperatives and municipalities. It provides distribution services to REPs, which sell electricity to retail customers. Oncor is also subject to the requirements of the ERCOT Protocols, including Nodal Protocols and ERCOT reliability standards as adopted and enforced by the TRE and the NERC.
Performance — Oncor achieved market-leading electricity delivery performance in 12 out of 14 key PUCT market metrics in 2010. 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 2010, Oncor invested $1.0 billion in its network to construct, rebuild and upgrade transmission lines and associated facilities, to extend the distribution infrastructure, and to pursue certain initiatives in infrastructure maintenance and information technology. Reflecting its commitment to infrastructure, in September 2008, Oncor and several other ERCOT utilities filed with the PUCT a plan to participate in the construction of transmission improvements designed to interconnect existing and future renewable energy facilities to transmit electricity from Competitive Renewable Energy Zones (CREZs) identified by the PUCT. In 2009, the PUCT awarded CREZ construction projects to Oncor, and Oncor currently estimates the costs of the projects to be approximately $1.75 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 2010, Oncor’s cumulative CREZ-related capital expenditures totaled $316 million, including $202 million invested in 2010. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulatory Matters – Oncor Matters with the PUCT.”
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Oncor’s technology upgrade initiatives include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs. Oncor’s plans provide for the full deployment of over three million advanced meters 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, 2010, Oncor has installed approximately 1,514,000 advanced digital meters, including 854,000 during the year ended December 31, 2010. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $360 million as of December 31, 2010, including $164 million invested in 2010. Oncor expects to complete installations of the advanced meters by the end of 2012.
In addition to the potential energy efficiencies from advanced metering, Oncor expects to invest over $300 million ($100 million in excess of regulatory requirements) over the five-year period ending 2012 in programs designed to improve customer electricity demand efficiencies. As of December 31, 2010, Oncor has invested $190 million in these programs, including $65 million in 2010, and 47% of the amount in excess of regulatory requirements has been spent.
In a stipulation with several parties that was approved by the PUCT in 2007 (as discussed in Note 6 to Financial Statements), 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 72% of this total was spent as of December 31, 2010. This spending does not include the CREZ facilities.
Electricity Transmission —Oncor’s electricity transmission business is responsible for the safe and reliable operations of its transmission network and substations. These responsibilities consist of the construction and maintenance of transmission facilities and substations and the monitoring, controlling and dispatching of high-voltage electricity over Oncor’s transmission facilities in coordination with ERCOT.
Oncor is a member of ERCOT, and its transmission business actively assists the operations of ERCOT and market participants. Through its transmission business, Oncor participates with ERCOT and other member utilities to plan, design, construct and operate new transmission lines, with regulatory approval, necessary to maintain reliability, interconnect to merchant generation facilities, increase bulk power transfer capability and minimize limitations and constraints on the ERCOT transmission grid.
Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to an interconnection to other markets, the FERC. Network transmission revenues compensate Oncor for delivery of electricity over transmission facilities operating at 60 kV and above. Other services offered by Oncor through its transmission business include, but are not limited to: system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.
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, 2010, Oncor’s transmission facilities included approximately 5,325 circuit miles of 345-kV transmission lines and approximately 9,979 circuit miles of 138-and 69-kV transmission lines. Sixty generation facilities totaling 34,357 MW are directly connected to Oncor’s transmission system, and 278 transmission stations and 705 distribution substations are served from Oncor’s transmission system.
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As of December 31, 2010, 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 | 6 | 21 | 3 | |||||||||
Texas Municipal Power Agency | 8 | 6 | — | |||||||||
Texas New Mexico Power | 2 | 9 | 11 | |||||||||
Brazos Electric Power Cooperative, Inc. | 6 | 109 | 20 | |||||||||
Rayburn Country Electric Cooperative, Inc. | — | 35 | 7 | |||||||||
City of Georgetown | — | 2 | — | |||||||||
Tex-La Electric Cooperative of Texas, Inc. | — | 12 | 1 | |||||||||
Other small systems operating wholly within Texas | — | 3 | 3 | |||||||||
| (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 3,118 distribution feeders.
The Oncor distribution system includes over 3.1 million points of delivery. Over the past five years, the number of distribution system points of delivery served by Oncor, excluding lighting sites, grew an average of approximately 1.23% per year, adding approximately 29,378 points of delivery in 2010.
The Oncor distribution system consists of approximately 56,374 miles of overhead primary conductors, approximately 21,559 miles of overhead secondary and street light conductors, approximately 15,490 miles of underground primary conductors and approximately 9,640 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 75 REPs in Oncor’s certificated service area, including TCEH. Distribution revenues from TCEH represented 36% of Oncor’s total revenues for 2010. Revenues from subsidiaries of Reliant Energy, Inc., each of which is a non-affiliated REP, represented 12% of Oncor’s total revenues for 2010. 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.
The PUCT has original jurisdiction over transmission and distribution rates and services in unincorporated areas and in those municipalities that have ceded original jurisdiction to the PUCT and has exclusive appellate jurisdiction to review the rate and service orders and ordinances of municipalities. Generally, PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that does not have the prior approval of the appropriate regulatory authority (PUCT or municipality with original jurisdiction). In accordance with a stipulation approved by the PUCT, Oncor filed a rate review with the PUCT in June 2008, based on a test year ended December 31, 2007. In August 2009, the PUCT issued a final order with respect to the rate review as discussed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulatory Matters.”
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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. If approved as requested, this review would result in an aggregate annual rate increase of approximately $353 million over the test year period adjusted for the impact of weather. Oncor also requested a revised regulatory capital structure of 55% debt to 45% equity. The debt-to-equity ratio established by the PUCT is currently set at 60% debt to 40% equity. The PUCT, cities and other participating parties, with input from Oncor, established a procedural schedule for the review in January 2011. A hearing on the merits of Oncor’s request is scheduled to commence in May 2011, and resolution of the proposed increase is expected to occur during the second half of 2011.
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—The Regulated Delivery segment includes Oncor’s wholly-owned, bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC. This financing subsidiary was organized for the limited purpose of issuing 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, 2010, $663 million principal amount of transition bonds were outstanding, which mature in the period from 2011 to 2016.
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Environmental Regulations and Related Considerations
Global Climate Change
Background — A growing concern has emerged nationally and internationally about global climate change and how greenhouse gas (GHG) emissions, such as CO2, might contribute to global climate change. We produce GHG emissions from the direct combustion of fossil fuels at our generation plants, primarily our lignite/coal-fueled generation units. CO2, methane and nitrous oxide are emitted in this combustion process, with CO2 representing the largest portion of these GHG emissions. GHG emissions (primarily CO2) from our combustion of fossil fuels represent the substantial majority of our total GHG emissions. For 2010, we estimate that our generation facilities produced 64 million short tons of CO2 based on continuously monitored data reported to and subject to approval by the EPA. Other aspects of our operations result in emissions of GHGs including, among other things, coal piles at our generation plants, sulfur hexafluoride in our electric operations, refrigerant from our chilling and cooling equipment, fossil fuel combustion in our motor vehicles and electricity usage at our facilities and headquarters. Because a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities, our financial condition and/or results of operations could be materially adversely affected by the enactment of statutes or regulations that mandate a reduction in GHG emissions or that impose financial penalties, costs or taxes on those that produce GHG emissions. See 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 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 adverse effect on our results of operations, financial position and liquidity.
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.
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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 then EPA Administrator Stephen Johnson on the issue of when the Clean Air Act’s Prevention of Significant Deterioration (PSD) program would apply to newly identified pollutants such as GHG’s. The EPA determined that the Clean Air Act’s PSD permit requirements would apply when a nation-wide rule requiring the control of a pollutant takes effect. Under this determination, PSD permitting requirements became applicable to GHG emissions from planned stationary sources or planned modifications to stationary sources that had not been issued a PSD permit by January 2, 2011 – the first date that new motor vehicles must meet the new GHG standards. Second, in April 2010, the EPA adopted GHG emission standards for certain new motor vehicles. Third, in June 2010, the EPA finalized its so-called “tailoring rule” that established new thresholds of GHG emissions for the applicability of permits under the Clean Air Act for stationary sources, including 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. In addition, in September 2009, the EPA issued a final rule requiring the reporting, by March 2011, of calendar year 2010 GHG emissions from specified large GHG emissions sources in the US (such reporting rule would apply to our lignite/coal-fueled generation facilities). If limitations on emissions of GHGs from existing sources are enacted, our costs of compliance could be material.
In December 2010, in response to the State of Texas’s indication that it would not take regulatory action to implement the EPA’s tailoring rule, the EPA adopted a rule to take over the issuance of permits for GHG emissions from the Texas Commission on Environmental Quality (TCEQ). The State of Texas is challenging that rule and the GHG permitting rules through litigation and has refused to implement the GHG permitting rules issued by the EPA. A number of members of the US Congress from both parties have introduced legislation to either block or delay EPA regulation of GHGs under the Clean Air Act, and legislative activity in this area over the next year is possible.
In September 2009, the US Court of Appeals for the Second Circuit issued a decision in the case ofState of Connecticut v. American Electric Power Company Inc. holding that various states, a municipality and certain private trusts have standing to sue and have sufficiently alleged a cause of action under the federal common law of nuisance for injuries allegedly caused by the defendant power generation companies’ emissions of GHGs. The decision does not address the merits of the nuisance claim. The US Supreme Court has agreed to review the Second Circuit’s decision.
In October 2009, the US Court of Appeals for the Fifth Circuit issued a decision in the case ofComer v. Murphy Oil USAreversing the district court’s dismissal of the case and holding that certain Mississippi residents did have standing to pursue state law nuisance, negligence and trespass claims for injuries purportedly suffered because the defendants’ emissions of GHGs allegedly increased the destructive force of Hurricane Katrina. The Fifth Circuit subsequently agreed to rehear the case, but then dismissed the appeal in its entirety when several judges recused themselves in the case. The Fifth Circuit’s order dismissing the appeal and vacating the earlier panel’s decision had the effect of reinstating the district court’s original dismissal of the case. In January 2011, the US Supreme Court rejected the plaintiffs’ request that their appeal be reinstated in the Fifth Circuit.
In September 2009, the US District Court for the Northern District of California issued a decision in the case ofNative Village of Kivalina v. ExxonMobil Corporation dismissing claims asserted by an Eskimo village that emissions of GHGs from approximately 24 oil and energy companies are causing global warming, which has damaged the arctic sea ice that protects the village from winter storms and erosion. The court dismissed the claims because they raised 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.
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 adverse effect on our business, results of operations and financial condition.
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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.
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 or Related Initiatives by Our Competitive Businesses — Our competitive businesses expect to invest $100 million in BrightenSMenergy saving solutions (energy efficiency) or related initiatives over a five-year period that began in 2008, including software- and hardware-based services deployed behind the meter. These programs leverage advanced meter interval data and in-home devices to provide usage and other information and insights to customers, as well as to control energy-consuming equipment. Examples of these initiatives include: the TXU Energy Electricity Usage Report, an electronic report which shows residential usage by week; the BrightenSM Personal Energy Advisor, an online energy audit tool with personalized tips and projects for saving electricity; the BrightenSM Online Energy Store that provides customers the opportunity to purchase hard-to-find, cost-effective energy-saving products; the BrightenSM Power Monitor, an in-home display device that enables residential customers to monitor whole-house energy usage and cost in real-time and projects month-end bill amounts; the BrightenSM iThermostat, a web-enabled programmable thermostat with a load control feature for cycling air conditioners during times of peak energy demand; time-based electricity rates that work in conjunction with advanced metering infrastructure; rate plans that include electricity from renewable resources; the BrightenSM Energy Efficiency Assistance Program that delivers products and services, as well as grants through social service agencies, to save energy at participating low income customer homes and apartment complexes; a program to refer customers to energy efficiency contractors, and the provision of rebates to business customers for purchasing new energy efficient equipment for their facilities through the Energy Efficiency Rebate Program; |
| • | Investing in Energy Efficiency Initiatives by Oncor — In addition to the potential energy efficiencies from advanced metering, Oncor expects to invest over $300 million in energy efficiency initiatives over a five-year period that began in 2008 through such efforts as traveling across the State of Texas educating consumers about electricity, including the benefits of energy efficiency, advanced meters and renewable energy, and investment of over $18 million in the installation of solar photovoltaic systems in customer homes and facilities that is expected to result in savings of up to 12.7 million kWh of electricity; |
| • | Participating in the CREZ Program — Oncor has been selected by the PUCT to construct CREZ transmission facilities (currently estimated by Oncor to cost $1.75 billion) that are designed to connect existing and future renewable energy facilities to the electricity transmission system in ERCOT; |
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| • | Purchasing Electricity from Renewable Sources — We expect to remain a leader in the ERCOT market in providing electricity from renewable sources by purchasing up to 1,500 MW of wind power. Our total wind power portfolio is currently more than 900 MW; |
| • | Promoting the Use of Solar Power— TXU Energy 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 — We have filed an application with the NRC for combined construction and operating licenses for up to 3,400 MW of new nuclear generation capacity (the lowest GHG emission source of baseload generation currently available) at our Comanche Peak nuclear generation facility. In addition, we have (i) filed a loan guarantee application with the DOE for financing of the proposed units and (ii) formed a joint venture with Mitsubishi Heavy Industries Ltd. (MHI) to further develop the units using MHI’s US-Advanced Pressurized Water Reactor technology, and |
| • | Offsetting GHG Emissions by Planting Trees —We are engaged in a number of tree planting programs that offset GHG emissions, resulting in the planting of over 1.3 million trees in 2010. 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 165,000 trees since its inception in 2002. |
Other Recent EPA Actions—The EPA has recently completed several regulatory actions establishing new requirements for control of certain emissions from sources that include lignite/coal-fueled generation facilities. It is also currently considering several other regulatory actions, as well as contemplating future additional regulatory actions, (the more material of which are discussed further below) in each case that may affect our lignite/coal-fueled generation facilities.
Each of our lignite/coal-fueled generation facilities is currently equipped with substantial emissions control equipment, including equipment installed as part of our commitment (in connection with the construction of the three recently completed lignite-fueled generation units) to reduce emissions of NOx, SO2 and mercury through the installation of emissions control equipment at both new and existing units and fuel blending at some existing units. All of 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. Some of the potential EPA or TCEQ regulatory actions could require us to install significant additional control equipment, resulting in material costs of compliance for our generation units, including capital expenditures and higher operating costs. These costs could result in material adverse effects on our financial condition, liquidity and results of operations.
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Sulfur Dioxide, Nitrogen Oxide and Mercury Air Emissions
The EPA has promulgated Acid Rain Program rules that require fossil-fueled plants to have sufficient SO2 emission allowances and meet certain NOxemission standards. Our generation plants meet these SO2 allowance requirements and NOx emission rates.
In 2005, the EPA issued a final rule to further reduce SO2 and NOx emissions from power plants. The SO2 and NOx reductions required under the Clean Air Interstate Rule (CAIR), which were required to be phased in between 2009 and 2015, were based on a cap and trade approach (market-based) in which a cap was put on the total quantity of emissions allowed in 28 eastern states (including Texas). Emitters were required to have allowances for each ton emitted, and emitters were allowed to trade emissions under the cap. In July 2008, the US Court of Appeals for the D.C. Circuit (D.C. Circuit Court) vacated CAIR. In December 2008, in response to an EPA petition, the D.C. Circuit Court reversed, in part, its previous ruling. Such reversal confirmed CAIR is not valid, but allowed it to remain in place while the EPA revises CAIR to correct the previously identified shortcomings. In July 2010, the EPA released a proposed rule called the Clean Air Transport Rule (CATR). The CATR, as proposed, would replace CAIR in 2012 and would require no additional emission reductions for Luminant. However, we cannot predict the impact of a final rule on our business, results of operations and financial condition. See Note 4 to Financial Statements for discussion of the impairment of emission allowances intangible assets in 2008.
SO2 reductions required under the proposed regional haze/visibility rule (or so-called BART rule) only apply to units built between 1962 and 1977. The reductions are required on a unit-by-unit basis. In February 2009, the TCEQ submitted a State Implementation Plan (SIP) concerning regional haze to the EPA, which we believe will not have a material impact on our generation facilities. The EPA has not made a decision on this SIP submittal.
The Clean Air Act requires each state to monitor air quality for compliance with federal health standards. The EPA is required to periodically review, and if appropriate, revise all national ambient quality standards. The standards for ozone are not being achieved in several areas of Texas. The TCEQ adopted SIP rules in May 2007 to deal with eight-hour ozone standards, which required NOx emission reductions from certain of our peaking natural gas-fueled units in the Dallas-Fort Worth area. In March 2008, the EPA made the eight-hour ozone standards more stringent. In January 2010, the EPA proposed to further reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. Since the EPA projects that SIP rules to address attainment of these new more stringent standards will not be required until December 2013, we cannot yet predict the impact of this action on our generation facilities. In January 2010, the EPA added a new one-hour NOx National Ambient Air Quality standard that may require actions within Texas to reduce emissions. The TCEQ will be required to revise its monitoring network and submit an implementation plan with compliance required no earlier than January 2021. In June 2010, the EPA adopted a new one-hour SO2 national ambient air quality standard that may require action within Texas to reduce SO2 emissions. The TCEQ will be required to conduct modeling and develop an implementation plan by 2014, pursuant to which compliance will be required by 2017, according to the EPA’s implementation timeline. 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 also published a final rule requiring reductions of mercury emissions from lignite/coal-fueled generation plants. The Clean Air Mercury Rule (CAMR) was based on a nationwide cap and trade approach. The mercury reductions were required to be phased in between 2010 and 2018. In March 2008, the D.C. Circuit Court vacated CAMR. In February 2009, the US Supreme Court refused to hear the appeal of the D.C. Circuit Court’s ruling. The EPA agreed in a consent decree submitted for court approval to propose Maximum Achievable Control Technology rules by March 2011 and finalize those rules by November 2011. We cannot predict the substance of any final EPA regulations on such hazardous air pollutants. However, the EPA has informally indicated that recently proposed regulations regarding hazardous air pollutants from industrial boilers may serve as a template for the forthcoming electricity generation unit regulations. The industrial boiler regulations, if applied to electricity generation units, would likely require material capital expenditures for additions of control equipment at our lignite/coal-fueled generation facilities.
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In September 2010, the EPA disapproved a portion of the SIP pursuant to which the TCEQ implements its program to achieve the EPA’s National Ambient Air Quality Standards (NAAQS) under the Clean Air Act. The EPA disapproved the Texas standard permit for pollution control projects. 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 the generation facility-specific permit conditions. The TCEQ is currently reviewing these applications. 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 this litigation.
In January 2011, the EPA retroactively disapproved a portion of the SIP pursuant to which the TCEQ issued permits for certain formerly non-permitted “grandfathered” facilities approximately 10 years ago. 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 intend to challenge the EPA’s disapproval by filing a lawsuit in the US Court of Appeals for the Fifth Circuit arguing that the TCEQ’s adoption of the standard permit was consistent with the Clean Air Act. If the EPA’s action stands, and if it causes us to undertake additional permitting activity and install additional emissions control equipment at our affected generation facilities, we could incur material capital expenditures.
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 adverse effects on our financial condition, liquidity and results of operations.
Water
The TCEQ and the EPA have jurisdiction over water discharges (including storm water) from facilities in Texas. 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.
We recently 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 adverse effects on our results of operations, liquidity and financial condition. (See Note 12 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 will require 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 believe we are currently in compliance with the new rules that become effective in November 2011.
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Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQ and the EPA. We believe we possess all necessary permits for these activities from the TCEQ for our present operations. 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 best professional judgment in reviewing applications and issuing permits under Section 316(b). The EPA has entered into a settlement agreement that requires it to propose new rules by March 2011 and to finalize those rules by July 2012. We cannot predict the impact on our operations of the suspended regulations or of new regulations that replace them.
Radioactive Waste
We currently ship low-level waste material to a disposal facility outside of Texas. Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the State of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. The State of Texas has agreed to a compact for a disposal facility that would be located in Texas. That compact was ratified by Congress and signed by the President in 1998. In 2003, the State of Texas enacted legislation allowing a private entity to be licensed to accept low-level radioactive waste for disposal, and in 2004 the State received a license application from such an entity for review. In January 2009, the TCEQ approved this permit. We expect to continue to ship low-level waste material off-site for as long as an alternative disposal site is available. Should existing off-site disposal become unavailable, the low-level waste material will be stored on-site. (See discussion under “Luminant – Nuclear Generation Operations” above.) 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.
We believe our on-site used nuclear fuel storage capability is sufficient for a minimum of three years. The nuclear industry is continuing to review ways to enhance security of used-fuel storage with the NRC to fully utilize physical storage capacity. Future on-site used nuclear fuel storage capability will require the use of the industry technique of dry cask storage.
Solid Waste, Including Fly Ash Associated with Lignite/Coal-Fueled Generation
Treatment, storage and disposal of solid waste and hazardous waste are regulated at the state level under the Texas Solid Waste Disposal Act and at the federal level under the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act. The EPA has issued regulations under the Resource Conservation and Recovery Act of 1976 and the Toxic Substances Control Act, and the TCEQ has issued regulations under the Texas Solid Waste Disposal Act applicable to 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.
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The EPA issued a notice in December 2009 that it had identified several industries, including the electric power industry, which should be subject to financial responsibility requirements under the Comprehensive Environmental Response, Compensation and Liability Act consistent with the risk associated with their production, transportation, treatment, storage or disposal of hazardous substances. The EPA indicated in its notice that it would develop regulations that define the scope of those financial responsibility requirements. We do not know, at this time, the scope of these requirements, nor are we able to estimate the potential cost (which could be material) of complying with any such new requirements.
Environmental Capital Expenditures
Capital expenditures for our environmental projects totaled $106 million in 2010 and are expected to total approximately $75 million in 2011, consisting primarily of environmental projects at existing lignite/coal-fueled generation plants. The 2010 amount is exclusive of emissions control equipment investment as part of the three-unit generation development program, which totaled approximately $500 million over the construction period. See discussion above under “Luminant – Lignite/Coal-Fueled Generation Operations” regarding planned investments in emissions control systems.
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| Item 1A. | RISK FACTORS |
Some important factors, in addition to others specifically addressed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” that could have a material negative impact on our operations, 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 and Debt Agreements
Our substantial leverage could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry, expose us to interest rate risk to the extent of our variable rate debt and prevent us from meeting obligations under the various debt agreements governing our debt.
We are highly leveraged. As of December 31, 2010, our consolidated principal amount of debt (short-term borrowings and long-term debt, including amounts due currently) totaled $36.7 billion (see Note 11 to Financial Statements), which does not include $5.446 billion principal amount of debt of Oncor. Our substantial leverage could have important consequences, including:
| • | making it more difficult for us to make payments on our debt; |
| • | requiring a substantial portion of 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 and future business opportunities and execute our strategy; |
| • | increasing our vulnerability to adverse economic, industry or competitive developments; |
| • | exposing us to the risk of increased interest rates because, as of December 31, 2010, taking into consideration interest swap transactions, 13% of our long-term borrowings were at variable rates of interest; |
| • | limiting our ability to make strategic acquisitions or causing us to make non-strategic divestitures; |
| • | limiting our ability to obtain additional financing for working capital, capital expenditures, product development, debt service requirements, acquisitions and general corporate or other purposes, or to refinance existing debt, and |
| • | limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to competitors who are less highly leveraged and who therefore, may be able to take advantage of opportunities that we cannot due to our substantial leverage. |
We may not be able to repay or refinance the TCEH Revolving Credit Facility, which matures in October 2013, other debt incurred under the TCEH Senior Secured Facilities, which matures in October 2014, or our other debt as or before it becomes due, particularly if forward natural gas prices do not significantly increase.
We may not be able to repay or refinance our debt obligations as or before they become due, or may be able to refinance such amounts only on terms that will increase our cost of borrowing or on terms that may be more onerous. Our ability to successfully implement any future refinancing of our debt will depend, 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) and general conditions in the credit markets. Refinancing may be difficult because of the slow economic recovery, the possibility of rising interest rates and the impending surge of large debt maturities of other borrowers. Due to the weakness of our credit, we may be more heavily exposed to these refinancing risks than other borrowers.
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A substantial amount of our debt is comprised of debt incurred under the TCEH Senior Secured Facilities, the majority of which matures in October 2014. The TCEH Revolving Credit Facility, which has a facility limit of $2.7 billion and availability of $1.4 billion (including $94 million of commitments from Lehman that are only available from the fronting banks and the swingline lenders) as of December 31, 2010, matures in October 2013. The TCEH Revolving Credit Facility is used for letters of credit and borrowings for general corporate purposes. We may not be able to refinance the TCEH Senior Secured Facilities, including the TCEH Revolving Credit Facility, or our other debt because of our high levels of existing debt. For example, we may not be able to refinance the TCEH Revolving Credit Facility unless prior to or concurrently with such refinancing we refinance or otherwise extend the maturity of a substantial portion of our debt due in 2014. Consequently, even though most of our debt matures in October 2014, the earlier maturity of the TCEH Revolving Credit Facility may effectively cause us to address the 2014 debt maturities at an earlier time than we might otherwise choose. Similarly, lenders of debt due in 2014 may be unwilling to refinance or otherwise extend the maturity of their lendings unless prior to or concurrently with such refinancing we refinance or otherwise extend the maturity of a substantial portion of our debt due in the period 2015 to 2017. As of December 31, 2010, $5.6 billion principal amount of our debt matures in the period 2015 to 2017. This “pull-forward” effect, which may cause us to refinance several maturities at once as the first becomes due, could increase our near-term refinancing needs.
Wholesale electricity prices in the ERCOT market largely correlate with the price of natural gas. Accordingly, the contribution to earnings and the value of our baseload generation assets are dependent in significant part upon the price of natural gas. Forward natural gas prices have generally trended downward since mid-2008. In recent years natural gas supply has outpaced demand as a result of increased drilling of shale gas deposits combined with lingering demand weakness associated with the economic recession, and many industry experts expect this supply/demand imbalance to continue for a number of years, thereby depressing natural gas prices for a long-term period. These market conditions are challenging to the long-term profitability of our generation assets. Specifically, low natural gas prices and their correlated effect in ERCOT on wholesale electricity prices could have a material adverse impact on the overall profitability of our generation assets for periods in which we do not have significant hedge positions. As of December 31, 2010, we have hedged only approximately 51% and 19% 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. A continuation of current forward natural gas prices or a further decline of forward natural gas prices could limit our ability to hedge our wholesale electricity revenues at sufficient price levels to support our interest payments and debt maturities, result in further declines in the values of our baseload generation assets and adversely impact our ability to refinance the TCEH Revolving Credit Facility due in October 2013 or our substantial debt due in October 2014.
In addition, 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, 2010. Our assets include $6.2 billion of goodwill as of December 31, 2010. In the third quarter 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. Recent valuation analyses of TCEH’s business indicate that the principal amount of its outstanding debt currently exceeds its enterprise value. We may have difficulty successfully implementing any refinancing of our debt due to our financial position as reflected in our balance sheet and the valuation analyses.
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 and repurchases of our debt that are described in Note 11 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 and adverse manner. Moreover, the effects of any of these transactions or initiatives could be material and adverse to holders of our debt and could be disproportionate, and directionally different, with respect to one class or type of debt than with respect to others.
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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 now face would intensify.
Increases in interest rates may negatively impact our results of operations, liquidity and financial condition.
Certain of our borrowings, to the extent the interest rate is not fixed by interest rate swaps, are at variable rates of interest. An increase in interest rates would have a negative impact on our results of operations by causing an increase in interest expense.
As of December 31, 2010, we had $4.494 billion aggregate principal amount of variable rate long-term debt (excluding $1.135 billion of long-term borrowings associated with the TCEH Letter of Credit Facility that are invested at a variable rate), taking into account interest rate swaps that fix the interest rate on $15.8 billion in notional amount of variable rate debt. As a result, as of December 31, 2010, a 100 basis point increase in interest rates would increase our annual interest expense by approximately $45 million. See discussion of interest rate swap transactions in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events.”
Our interest expense and related charges for the year ended December 31, 2010 totaled $3.554 billion, including $207 million of unrealized mark-to-market net losses on interest rate swaps.
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 11 to Financial Statements for a description of these covenants and other restrictions.
Under the TCEH Senior Secured Facilities, TCEH is required to maintain a consolidated secured debt to consolidated EBITDA ratio below specified levels. TCEH’s ability to maintain the consolidated secured debt to consolidated EBITDA ratio below such levels can be affected by events beyond its control, including, without limitation, wholesale electricity prices (which are primarily derived by the price of natural gas and ERCOT market heat rates), and there can be no assurance that TCEH will comply with this ratio.
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A breach of any of these covenants or restrictions could result in an event of default under one or more of our debt agreements, including as a result of cross default provisions. Upon the occurrence of an event of default under one of the debt agreements, 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 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 borrowings, we may 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. |
We may not be able to generate sufficient cash to service all of our debt and may be forced to take other actions to satisfy our obligations under our debt agreements, which may not be successful.
Our ability to make scheduled payments on 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). We may not be able to maintain a level of cash flows sufficient to permit us to pay the principal, premium, if any, and interest on our debt.
If cash flows and capital resources are insufficient to fund our debt service obligations, we could face substantial liquidity problems and might be forced to reduce or delay investments and capital expenditures, or to dispose of assets or operations, seek additional capital or restructure or refinance 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 service 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 allowed, under these documents, to use proceeds from these dispositions to satisfy our debt service obligations.
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Under the terms of the indentures governing the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities, TCEH is restricted from making certain payments to EFH Corp.
EFH Corp. is a holding company and substantially all of its reported consolidated assets are held by its subsidiaries. As of December 31, 2010, TCEH and its subsidiaries held approximately 80% of EFH Corp.’s reported consolidated assets and for the year ended December 31, 2010, TCEH and its subsidiaries represented all of EFH Corp.’s reported consolidated revenues. Accordingly, EFH Corp. depends upon TCEH for a significant amount of its cash flows and relies on such cash flows in order to pay its obligations. However, under the terms of the indentures governing the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities, TCEH is restricted from making certain payments to EFH Corp., except in the form of certain loans to cover certain of EFH Corp.’s obligations and dividends and distributions in certain other limited circumstances if permitted by applicable state law. Further, the indentures governing the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes and the terms of the TCEH Senior Secured Facilities do not permit such intercompany loans to service EFH Corp. debt unless required for EFH Corp. to pay principal, premium and interest when due on 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 to service other debt, subject to limitations on the amount of the loans. As a result, unless and until the net proceeds from the offering of any notes by EFH Corp. are used to replace, refund or refinance EFH Corp. debt, intercompany loans from TCEH to EFH Corp. to make payments on such notes are restricted. In addition, TCEH is prohibited from making certain loans to EFH Corp. if certain events of default under the indentures governing the TCEH Senior Notes or the TCEH Senior Secured Second Lien Notes or the terms of the TCEH Senior Secured Facilities have occurred and are continuing.
Under the terms of the indentures governing the EFIH Notes, EFIH is restricted from making certain payments to EFH Corp.
EFH Corp. is a holding company and substantially all of its consolidated assets are held by its subsidiaries. As of December 31, 2010, EFIH and its subsidiaries held approximately 12% of EFH Corp.’s consolidated assets, which assets consist primarily of EFIH’s investment in Oncor Holdings. Accordingly, EFH Corp. depends upon EFIH for a significant amount of its cash flows and relies on such cash flows in order to pay its obligations. However, under the terms of the indenture governing the EFIH Notes, EFIH is restricted from making certain payments, including dividends and loans, to EFH Corp., except in limited circumstances.
EFH Corp. has a very limited ability to control activities at Oncor due to structural and operational “ring-fencing” measures.
EFH Corp. depends upon Oncor for a significant amount of its cash flows and relies on such cash flows in order to pay its obligations. However, EFH Corp. has a very limited ability to control the activities of Oncor. As part of the “ring-fencing” measures implemented by EFH Corp. and Oncor, a majority of the members of Oncor’s board of directors are required to meet the New York Stock Exchange requirements for independence in all material respects, and the unanimous, 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 the following: new issuances of equity securities by Oncor, material transactions with third parties involving Oncor outside of the ordinary course of business, actions that cause Oncor’s assets to increase the level of jurisdiction of the FERC, any changes to the state of formation of Oncor, material changes to accounting methods not required by US GAAP, and actions that fail to enforce certain tax sharing obligations between Oncor and EFH Corp. In addition, there are restrictions on Oncor’s ability to make distributions to its members, including indirectly to EFH Corp.
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Risks Related to Structure
EFH Corp. is a holding company and its obligations are structurally subordinated to existing and future liabilities and preferred stock of its subsidiaries.
EFH Corp.’s cash flows and ability to meet its obligations are largely dependent upon the earnings of its subsidiaries and the payment of such earnings to EFH Corp. in the form of dividends, distributions, loans or otherwise, and repayment of loans or advances from EFH Corp. These subsidiaries are separate and distinct legal entities and have no obligation to provide EFH Corp. with funds for its payment obligations. Any decision by a subsidiary to provide EFH Corp. with funds for its payment obligations, whether by dividends, distributions, loans or otherwise, will depend on, among other things, the subsidiary’s results of operations, financial condition, cash requirements, contractual restrictions and other factors. In addition, a subsidiary’s ability to pay dividends may be limited by covenants in its existing and future debt agreements or applicable law. Further, the distributions that may be paid by Oncor are limited as discussed below.
Because EFH Corp. is a holding company, its obligations to its creditors are structurally subordinated to all existing and future liabilities and existing and future preferred stock of its subsidiaries that do not guarantee such obligations. Therefore, with respect to subsidiaries that do not guarantee EFH Corp.’s obligations, EFH Corp.’s rights and the rights of its creditors to participate in the assets of any subsidiary in the event that such a subsidiary is liquidated or reorganized are subject to the prior claims of such subsidiary’s creditors and holders of such subsidiary’s preferred stock. To the extent that EFH Corp. may be a creditor with recognized claims against any such subsidiary, EFH Corp.’s claims would still be subject to the prior claims of such subsidiary’s creditors to the extent that they are secured or senior to those held by EFH Corp. Subject to restrictions contained in financing arrangements, EFH Corp.’s subsidiaries may incur additional debt and other liabilities.
Oncor may or may not make any distributions to EFH Corp.
Upon the consummation of the Merger, EFH Corp. and Oncor implemented certain structural and operational “ring-fencing” measures, 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. 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. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulatory Matters — Oncor Matters with the PUCT” for discussion of a rate review filed by Oncor in January 2011 that, among other things, requested a revised regulatory capital structure of 55% debt to 45% equity.
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In March 2009, the PUCT awarded Oncor the right to construct transmission lines and facilities associated with its CREZ Transmission Plan, the cost of which is currently estimated by Oncor to be approximately $1.75 billion (see discussion in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulatory Matters”). With the award, it is likely Oncor will incur additional debt. In addition, Oncor may incur additional debt in connection with other investments in infrastructure or technology, including automated accounting systems. 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 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 activities by EFH Corp. or any of its subsidiaries. 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 2008 general rate case or subsequent rate cases.
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Risks Related to Businesses
Our businesses are subject to ongoing complex governmental regulations and legislation that have impacted, and may in the future impact, our businesses and/or results of operations.
Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory initiatives regarding the restructuring of the energy industry, including competition in the generation and sale of electricity. We will need to continually adapt to these changes.
Our businesses are subject to changes in state and federal laws (including PURA, the Federal Power Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act and the Energy Policy Act of 2005), changing governmental policy and regulatory actions (including those of the PUCT, the NERC, the TRE, the RRC, the TCEQ, the FERC, the EPA, the NRC and the CFTC) and the rules, guidelines and protocols of ERCOT with respect to matters including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, construction and operation of transmission facilities, acquisition, disposal, depreciation and amortization of regulated assets and facilities, recovery of costs and investments, decommissioning costs, return on invested capital for regulated businesses, market behavior rules, present or prospective wholesale and retail competition and environmental matters. TCEH, along with other market participants, is subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA that are administered by the PUCT and ERCOT, and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior and other competition-related rules and regulations under the Federal Power Act that are administered by the FERC. Changes in, revisions to, or reinterpretations of existing laws and regulations (for example, with respect to prices at which TCEH may sell electricity, or the cost of emitting greenhouse gases) may have a material and adverse effect on our businesses.
The Texas Legislature meets every two years (the current legislative session began in January 2011), and from time to time bills are introduced and considered that could materially affect our businesses. The State of Texas currently faces a substantial budget deficit, and the Texas Legislature is expected to enact spending cuts to address this shortfall. We cannot predict whether spending cuts or other actions taken with respect to the budget deficit will affect the PUCT or other agencies that relate to our business or whether any such spending cuts or other actions taken with respect to the budget deficit will have a material impact on our business. There can be no assurance that future action of the Texas Legislature will not result in legislation that could have a material adverse effect on us and our financial prospects.
PURA, the PUCT, ERCOT, the RRC, the TCEQ and the Office of Public Utility Council (OPC) are subject to a “Sunset” review by the Texas Sunset Advisory Commission. PURA will expire, and the PUCT and the RRC will be abolished, on September 1, 2011 unless extended by the Texas Legislature following such review. If any of PURA, the PUCT, ERCOT, the RRC, the TCEQ or the OPC are not renewed by the Texas Legislature pursuant to Sunset review, it could have a material effect on our business.
Sunset review is the regular assessment of the continuing need for a state agency to exist, and is grounded in the premise that an agency will be abolished unless legislation is passed to continue its functions. The Texas Sunset Advisory Commission (Sunset Commission) closely reviews each agency and recommends action on each agency to the Texas Legislature, which action may include modifying or even abolishing the agency. Of the agencies scheduled for Sunset review by the Sunset Commission in 2010 and 2011, the following hold primary interest for us and are subject to a focused, limited scope, or special purpose review: the TCEQ, the PUCT, the OPC, the RRC and ERCOT. These agencies, for the most part, govern and operate the electricity and mining markets in Texas upon which our business model is based. PURA, which expires September 1, 2011, is also subject to Sunset review. If the Texas Legislature fails to renew PURA or any of these agencies, it could result in a significant restructuring of the Texas electricity market or regulatory regime that could have a material impact on our business. There can be no assurance that future action of the Sunset Commission will not result in legislation that could have a material adverse effect on us and our financial prospects.
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Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputation damage, and have a material adverse effect on our results of operations, and the litigation environment in which we operate poses a significant risk to our businesses.
We are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, 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 assessments and estimates, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These assessments and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current assessments and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on our results of operations. In addition, judges and juries in the State of Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage and business tort cases. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment in the State of Texas poses a significant business risk.
We are involved in the ordinary course of business in permit applications and renewals, and we are exposed to the risk that certain of our operating permits may not be granted or renewed on satisfactory terms. Failure to obtain and maintain the necessary permits to conduct our businesses could have a material adverse effect on our results of operations.
We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings. See 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 adverse effect on our results of operations and liquidity.
TCEH’s revenues and results of operations may be negatively impacted by decreases in market prices for electricity, decreases in natural gas prices, and/or decreases in market heat rates.
TCEH (our largest business) is not guaranteed any rate of return on capital investments in its competitive businesses. We market and trade electricity and natural gas, including electricity from our own generation facilities and generation contracted from third parties, as part of our wholesale markets operation. TCEH’s results of operations depend in large part upon wholesale market prices for electricity, natural gas, uranium, coal and transportation in its regional market and other competitive markets and upon prevailing retail electricity rates, which may be impacted by actions of regulatory authorities. Market prices may fluctuate substantially over relatively short periods of time. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, at times there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets.
Some of the fuel for our generation facilities is purchased under short-term contracts. Prices of fuel, including diesel, natural gas, coal, and nuclear fuel, may also be volatile, and the price we can obtain for electricity sales may not change at the same rate as changes in fuel costs. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting obligations.
Volatility in market prices for fuel and electricity may result from the following:
| • | volatility in natural gas prices; |
| • | volatility in market heat rates; |
| • | volatility in coal and rail transportation prices; |
| • | severe or unexpected weather conditions; |
| • | seasonality; |
| • | changes in electricity and fuel usage; |
| • | illiquidity in the wholesale power or other markets; |
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| • | 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. |
All of our generation facilities are located in the ERCOT market, a market with limited interconnections to other markets. Wholesale electricity prices in the ERCOT market generally correlate with the price of natural gas because marginal electricity demand is generally supplied by natural gas-fueled generation facilities. Accordingly, our earnings and the value of our baseload generation assets, which provided a substantial portion of our supply volumes in 2010, are dependent in significant part upon the price of natural gas. Forward natural gas prices have generally trended downward since mid-2008. In recent years natural gas supply has outpaced demand as a result of increased drilling of shale gas deposits combined with lingering demand weakness associated with the economic recession, and many industry experts expect this supply/demand imbalance to continue for a number of years, thereby depressing natural gas prices for a long-term period. While our hedging activities, in particular our long-term hedging program, are designed to mitigate the effect on earnings of low wholesale electricity prices, due to low natural gas prices, these market conditions are challenging to the long-term profitability of our generation assets. Specifically, the low natural gas prices and the correlated effect in ERCOT on wholesale power prices could have a material adverse impact on the overall profitability of 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 2011 and 2012 (approximately 99% and 87%, respectively), as of December 31, 2010, we have hedged only approximately 51% and 19% 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. A continuation of current forward natural gas prices or a further decline of forward natural gas prices could limit our ability to hedge our wholesale electricity revenues at sufficient price levels to support our interest payments and debt maturities, result in further declines in the value of our baseload generation assets and could adversely impact our ability to refinance the TCEH Revolving Credit Facility due in October 2013 or our substantial debt due in October 2014.
Wholesale electricity prices also correlate with market heat rates (a measure of efficiency of the marginal price-setting generator of electricity), which could fall if demand for electricity were to decrease or if additional generation facilities are built in ERCOT. Accordingly, our earnings and the value of our baseload (lignite/coal-fueled and nuclear) generation assets, which provided a substantial portion of our supply volumes in 2010, are also dependent in significant part upon market heat rates. As a result, our baseload generation assets could significantly decrease in profitability and value if market heat rates continue at current levels or decline.
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 and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Although we devote a considerable amount of time and effort to the establishment of risk management procedures, as well as the ongoing review of the implementation of these procedures, the procedures in place may not always function as planned and cannot eliminate all the risks associated with these activities. For example, we hedge the expected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters, market constraints or other factors could cause us to purchase power to meet unexpected demand in periods of high wholesale market prices or resell excess power into the wholesale market in periods of low prices. As a result of these and other factors, we cannot precisely predict the impact that risk management decisions may have on our businesses, results of operations, 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 market transactions 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 and make them applicable to 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 OTC derivatives to hedge our commodity and interest rate risks would be significantly limited.
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We cannot predict the outcome of the rulemakings to implement the OTC derivative market provisions of the Financial Reform Act. These rulemakings could negatively affect our ability to hedge our commodity and interest rate risks. The inability to hedge these risks would likely have a material adverse effect on our results of operations, liquidity or financial condition.
We may suffer material losses, costs and liabilities due to ownership and operation of the Comanche Peak nuclear generation facility.
The ownership and operation of a nuclear generation facility involves certain risks. These risks include:
| • | unscheduled outages or unexpected costs due to equipment, mechanical, structural or other problems; |
| • | inadequacy or lapses in maintenance protocols; |
| • | the impairment of reactor operation and safety systems due to human error; |
| • | the costs of storage, handling and disposal of nuclear materials, including availability of storage space; |
| • | the costs of procuring nuclear fuel; |
| • | the costs of securing the plant against possible terrorist attacks; |
| • | limitations on the amounts and types of insurance coverage commercially available, and |
| • | uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. |
The prolonged unavailability of Comanche Peak could materially affect our financial condition and results of operations. The following are among the more significant of these risks:
| • | Operational Risk — Operations at any nuclear generation facility could degrade to the point where the facility would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availability at Comanche Peak. |
| • | Regulatory Risk — The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unless extended, the NRC operating licenses for Comanche Peak Unit 1 and Unit 2 will expire in 2030 and 2033, respectively. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs. |
| • | 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. |
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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 (a) increased starting and stopping of generation equipment due to the volatility of the competitive generation market and the prospect of continuing low wholesale electricity prices that may not justify sustained or year-round operation of all our generating facilities, (b) any unexpected failure to generate electricity, including failure caused by equipment breakdown or forced outage and (c) damage to facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events. Further, 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.
Maintenance, expansion and refurbishment of power generation facilities involve significant risks that could result in unplanned power outages or reduced output and could have a material adverse effect on our results of operations, liquidity and financial condition.
Many of our facilities are old and require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could materially adversely affect 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 attacks). The unexpected requirement of large capital expenditures could materially adversely 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 substantial additional capital expenditures.
Our cost of compliance with environmental laws and regulations and our commitments, and the cost of compliance with new environmental laws, regulations or commitments could materially adversely affect our results of operations, 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.
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The EPA has recently completed several regulatory actions establishing new requirements for control of certain emissions from sources that include coal-fueled generation facilities. It is also currently considering several other regulatory actions, as well as contemplating future additional regulatory actions, in each case that may affect our coal-fueled generation facilities. There is no assurance that the currently-installed emissions control equipment at our coal-fueled generation facilities will satisfy the requirements under any future EPA or TCEQ regulations. Some of the potential EPA or TCEQ regulatory actions could require us to install significant additional control equipment, resulting in material costs of compliance for our generation units, including capital expenditures, higher operating costs and potential production curtailments. These costs could result in material adverse effects on our results of operations, liquidity and financial condition.
In conjunction with the building of three new generation units, we have committed to reduce emissions of mercury, NOX and SO2 through the installation of emissions control equipment at both the new and existing lignite-fueled generation units. We may incur significantly greater costs than those contemplated in order to achieve this commitment.
We have formed a Sustainable Energy Advisory Board that advises us in our pursuit of technology development opportunities that, among other things, are designed to reduce our impact on the environment. Any adoption of Sustainable Energy Advisory Board recommendations may cause us to incur significant costs in addition to the costs referenced above.
We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain, maintain or comply with any such approval or if an approval is retroactively disallowed, the operation and/or construction of our facilities could be stopped, curtailed or modified or become subject to additional costs.
In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that we have acquired, leased or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against us or fail to meet its indemnification obligations to us.
Our results of operations, liquidity and financial condition may be materially adversely affected if new federal and/or state legislation or regulations are adopted to address global climate change.
In recent years, a growing concern has emerged about global climate change and how greenhouse gas (GHG) emissions, such as CO2, contribute to global climate change. Several bills addressing climate change have been introduced in the US Congress or discussed by the Obama Administration that are intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), incentives for the development of low-carbon technology and federal renewable portfolio standards. In addition, a number of federal court cases have been recently decided that could result in the future regulation of GHG emissions.
The EPA recently issued a rule, known as the Prevention of Significant Deterioration (PSD) tailoring rule, which establishes new thresholds for regulating GHG emissions from stationary sources under the Clean Air Act. Beginning in January 2011, the rule requires any source subject to the PSD permitting program due to emissions of non-GHG pollutants that increases its GHG emissions by 75,000 tons per year (tpy) to have an operating permit under the Title V Operating Permit Program of the Clean Air Act and install the best available control technology in conjunction with construction activities or plant modifications. Beginning in July 2011, PSD permitting requirements will also apply to new projects with GHG emissions of at least 100,000 tpy and modifications to existing facilities that increase GHG emissions by at least 75,000 tpy (even if no non-GHG PSD thresholds are exceeded). The EPA also finalized regulations in 2009 that will require certain categories of GHG emitters (including our lignite-fueled generation facilities) to monitor and report their annual GHG emissions beginning in March 2011.
The EPA also announced in late 2010 its intent to promulgate, in 2011, GHG emission limits known as New Source Performance Standards that would apply to new and modified sources, as well as GHG emission guidelines that states might apply to existing sources of GHGs. The EPA has indicated that such new standards and guidelines would be applicable to electricity generation facilities. We cannot predict what limits or guidelines the EPA might adopt. If the 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 adverse effect on our results of operations, liquidity and financial condition.
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We produce GHG emissions from the combustion of fossil fuels at our generation facilities. For 2010, we estimate that our generation facilities produced 64 million short tons of CO2 based on continuously monitored data reported to and subject to approval by the EPA. Because a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities, our results of operations, liquidity and financial condition could be materially adversely affected by the enactment of any legislation or regulation that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes upon those that produce GHG emissions. For example, to the extent a cap-and-trade program is adopted, we may be required to incur material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with such a program. The EPA regulation of GHGs under the Clean Air Act, or judicially imposed limits on GHG emissions, may require us to make material expenditures to reduce our GHG emissions. If a significant number of our customers or others refuse to do business with us because of our GHG emissions, it could have a material adverse effect on our results of operations, liquidity or financial condition.
Our results of operations, liquidity and financial condition may be materially adversely 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 or storms or other natural disasters, could be destructive and result in casualty losses that are not ultimately offset by insurance proceeds or in increased capital expenditures or costs, including supply chain costs.
Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, an extreme weather event might affect the availability of generation and transmission capacity, limiting our ability to source or deliver electricity to where it is needed. These conditions, which cannot be reliably predicted, could have an adverse consequence by requiring us to seek additional sources of electricity when wholesale market prices are high or to seek to sell excess electricity when those market prices are low.
The rates of Oncor’s electricity delivery business are subject to regulatory review, and may be reduced below current levels, which could adversely impact Oncor’s 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 in Oncor’s balance sheet, and the return on invested capital allowed by the PUCT. In January 2011, Oncor filed for a rate review with the PUCT and 203 cities as discussed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulatory Matters.” In its filing, Oncor requested an aggregate annual rate increase of approximately $353 million and a revised regulatory capital structure of 55% debt to 45% equity. The debt-to-equity ratio established by the PUCT is currently set at 60% debt to 40% equity. We cannot predict the outcome of this rate review.
In addition, in connection with the Merger, Oncor has made several commitments to the PUCT regarding its rates. For example, Oncor committed that it will, in rate cases after its 2008 general rate case through proceedings initiated prior to December 31, 2012, support a cost of debt that will be no greater than the then-current cost of debt of electric utilities with investment grade credit ratings equal to Oncor’s ratings as of October 1, 2007. As a result, Oncor may not be able to recover all of its debt costs if they are above those levels.
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Ongoing performance improvement initiatives may not achieve desired cost reductions and may instead result in significant additional costs if unsuccessful.
The implementation of performance improvement initiatives identified by management may not produce the desired reduction in costs and if unsuccessful, may instead result in significant additional costs as well as significant disruptions in our operations due to employee displacement and the rapid pace of changes to organizational structure and operating practices and processes. Such additional costs or operational disruptions could have an adverse effect on our businesses and financial prospects.
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 adverse effect on our financial condition, results of operations and liquidity.
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 legal claims, impair our ability to execute on business strategies and/or materially and adversely affect our financial condition, results of operations and liquidity.
TXU Energy may lose a significant number of retail customers due to competitive marketing activity by other retail electric providers.
TXU Energy faces competition for customers. Competitors may offer lower prices and other incentives, which, despite TXU Energy’s long-standing relationship with customers, may attract customers away from TXU Energy.
In some retail electricity markets, TXU Energy’s principal competitor may be the incumbent REP. The incumbent REP has the advantage of long-standing relationships with its customers, including well-known brand recognition.
In addition to competition from the incumbent REP, TXU Energy may face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with TXU Energy. Some of these competitors or potential competitors may be larger or better capitalized than TXU Energy. If there is inadequate potential margin in these retail electricity markets, it may not be profitable for TXU Energy to compete in these markets.
TXU Energy’s retail business is subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to its reputation and/or the results of operations of the retail business.
TXU Energy’s retail business requires access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, drivers license numbers, social security numbers and bank account information. TXU Energy’s retail business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the retail business. If a significant breach occurred, the reputation of TXU Energy’s retail business may be adversely affected, customer confidence may be diminished, or TXU Energy’s retail business may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the business and/or results of operations.
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TXU Energy relies on the infrastructure of local utilities or independent transmission system operators to provide electricity to, and to obtain information about, its customers. Any infrastructure failure could negatively impact customer satisfaction and could have a material negative impact on its business and results of operations.
TXU Energy depends on transmission and distribution facilities owned and operated by unaffiliated utilities, as well as Oncor’s facilities, to deliver the electricity it sells to its customers. If transmission capacity is inadequate, TXU Energy’s ability to sell and deliver electricity may be hindered, and it may have to forgo sales or buy more expensive wholesale electricity than is available in the capacity-constrained area. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where TXU Energy has a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower profits. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to TXU Energy’s customers could negatively impact the satisfaction of its customers with its service.
TXU Energy offers bundled services to its retail customers, with some bundled services offered at fixed prices and for fixed terms. If TXU Energy’s costs for these bundled services exceed the prices paid by its customers, its results of operations could be materially adversely affected.
TXU Energy offers its customers a bundle of services that include, at a minimum, electricity plus transmission, distribution and related services. The prices TXU Energy charges for its bundle of services or for the various components of the bundle, any of which may be fixed by contract with the customer for a period of time, could fall below TXU Energy’s underlying cost to provide the components of such services.
TXU Energy’s REP certification is subject to PUCT review.
The PUCT may at any time initiate an investigation into whether TXU Energy is compliant with PUCT Substantive Rules and whether it has met all of the requirements for REP certification, including financial requirements. Any removal or revocation of a REP certification would mean that TXU Energy would no longer be allowed to provide electricity service to retail customers. Such decertification would have a material and adverse effect on the company and its financial prospects.
Changes in technology or increased electricity conservation efforts may reduce the value of 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 by a fixed date. Effective energy conservation by our customers could result in reduced energy demand or significantly slow the growth in demand. Such reduction in demand could materially reduce our revenues. Furthermore, we may incur increased capital expenditures if we are required to invest in conservation measures.
Our revenues and results of operations may be adversely impacted by decreases in market prices of power due to the development of wind generation power sources.
A significant amount of investment in wind generation in the ERCOT market over the past few years has increased overall wind power generation capacity. Generally, the increased capacity has led to lower wholesale electricity prices (driven by lower market heat rates) in the 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.
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Our revenues and results of operations may be adversely impacted by the ERCOT market’s recent transition from a zonal to a nodal wholesale market structure.
Substantially all of our competitive businesses are located in the ERCOT market, which has recently transitioned from a zonal market structure with four congestion management zones to a nodal market structure that directly manages congestion on a localized basis. In a nodal market, the prices received and paid for power are based on pricing determined at specific interconnection points on the transmission grid (i.e., Locational Marginal Pricing), which could result in lower revenues or higher costs for our competitive businesses. This market structure change could have a significant impact on the profitability and value of our competitive businesses depending on how the Locational Marginal Pricing develops, particularly if such development ultimately results in lower revenue due to lower wholesale electricity prices, increased costs to service end-user electricity demand or increased collateral posting requirements with ERCOT. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Activities and Events — Wholesale Market Design — Nodal Market.”
Our future results of operations may be negatively impacted by settlement adjustments determined by ERCOT related to prior periods.
ERCOT is the independent system operator that is responsible for maintaining reliable operation of the bulk electric power supply system in the ERCOT market. Its responsibilities include the clearing and settlement of electricity volumes and related ancillary services among the various participants in the deregulated Texas market. Settlement information for most operating activity is due from ERCOT within two months after the operating day, and true-up settlements are due from ERCOT within six months after the operating day. Likewise, ERCOT has the ability to resettle any operating day at any time after the six month settlement period, usually the result of a lingering dispute, an alternative dispute resolution process or litigated event. As a result, we are subject to settlement adjustments from ERCOT related to prior periods, which may result in charges or credits impacting our future reported results of operations.
Our results of operations and financial condition could be negatively impacted by any development or event beyond our control that causes economic weakness in the ERCOT market.
We derive substantially all of our revenues from operations in the ERCOT market, which covers approximately 75% of the geographical area in the State of Texas. As a result, regardless of the state of the economy in areas outside the ERCOT market, economic weakness in the ERCOT market could lead to reduced demand for electricity in the ERCOT market. Such a reduction could have a material negative impact on our results of operations, liquidity and financial condition.
EFH Corp.’s (or any applicable subsidiary’s) credit ratings could negatively affect EFH Corp.’s (or the pertinent subsidiary’s) ability to access capital and could require EFH Corp. or its subsidiaries to post collateral or repay certain indebtedness.
Downgrades in EFH Corp.’s or any of its applicable subsidiaries’ long-term debt ratings generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease and could trigger liquidity demands pursuant to the terms of new commodity contracts, leases or other agreements. Future transactions by EFH Corp. or any of its subsidiaries, including the issuance of additional debt or the consummation of 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. If EFH Corp.’s (or an applicable subsidiary’s) credit ratings decline, the costs to operate its businesses would likely increase because counterparties could require the posting of collateral in the form of cash-related instruments, or counterparties could decline to do business with EFH Corp. (or its applicable subsidiary).
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Market volatility may have impacts on our businesses and financial condition that we currently cannot predict.
Because our operations are capital intensive, we expect to rely over the long-term upon access to financial markets (particularly the attainment of liquidity facilities) as a significant source of liquidity for capital requirements not satisfied by cash-on-hand, operating cash flows or our revolving credit facilities. The capital and credit markets experienced extreme volatility and disruption in 2008 and 2009. Our ability to access the capital or credit markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. In addition, the cost of debt financing may be materially impacted by these market conditions. Accordingly, there can be no assurance that the capital and credit markets will continue to be a reliable or acceptable source of short-term or long-term financing for us. Additionally, disruptions in the capital and credit markets could have a broader impact on the economy in general in ways that could lead to reduced electricity usage, which could have a negative impact on our revenues, or have an impact on our customers, counterparties and/or lenders, causing them to fail to meet their obligations to us.
Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets and/or during times when there are significant changes in commodity prices. The inability to access liquidity, particularly on favorable terms, could materially adversely affect results of operations and/or financial condition.
Our businesses are capital intensive. We rely on access to financial markets and liquidity facilities as a significant source of liquidity for capital requirements not satisfied by cash-on-hand or operating cash flows. The inability to raise capital on favorable terms or access liquidity facilities, particularly during times of uncertainty similar to those experienced in the financial markets in 2008 and 2009, could impact our ability to sustain and grow our businesses and would likely increase capital costs. Our access to the financial markets and liquidity facilities could be adversely impacted by various factors, such as:
| • | changes in financial markets that reduce available credit or the ability to obtain or renew liquidity facilities on acceptable terms; |
| • | economic weakness in the ERCOT or general US market; |
| • | changes in interest rates; |
| • | a deterioration of EFH Corp.’s credit or the credit of its subsidiaries or a reduction in EFH Corp.’s or its applicable subsidiaries’ credit ratings; |
| • | a deterioration of the credit or bankruptcy of one or more lenders or counterparties under our liquidity facilities that affects the ability of such lender(s) to make loans to us; |
| • | volatility in commodity prices that increases margin or credit requirements; |
| • | a material breakdown in our risk management procedures, and |
| • | the occurrence of changes in our businesses that restrict our ability to access liquidity facilities. |
Although we expect to actively manage the liquidity exposure of existing and future hedging arrangements, given the size of the long-term hedging program, any significant increase in the price of natural gas could result in us being required to provide cash or letter of credit collateral in substantial amounts. While these potential posting obligations are primarily supported by the liquidity facilities, for certain transactions there is a potential for the timing of postings on the commodity contract obligations to vary from the timing of borrowings from the TCEH Commodity Collateral Posting Facility. Any perceived reduction in our credit quality could result in clearing agents or other counterparties requesting additional collateral. We have credit concentration risk related to the limited number of lenders that provide liquidity to support our hedging program. A deterioration of the credit quality of such lenders could materially affect our ability to continue such program on acceptable terms. An event of default by one or more of our hedge counterparties could result in termination-related settlement payments that reduce available liquidity if we owe amounts related to commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us. These events could have a material negative impact on our 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.
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In the event our liquidity facilities are being used largely to support the long-term hedging program as a result of a significant increase in the price of natural gas or significant reduction in credit quality, we may have to forego certain capital expenditures or other investments in our competitive businesses or other business opportunities.
Further, a lack of available liquidity could adversely impact the evaluation of our creditworthiness by counterparties and rating agencies. In particular, such concerns by existing and potential counterparties could significantly limit TCEH’s wholesale markets activities, including its long-term hedging program.
The costs of providing pension and OPEB and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our results of operations, 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, such as the substantial dislocation that began in 2008. Significant decreases in the values of these investments could increase the expenses of the pension plan and the costs of the OPEB plans and related funding requirements in the future. 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 20 to Financial Statements for further discussion of our pension and OPEB plans.
As was the case in the third quarter 2010 (as discussed in Note 4 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, and as a result, we could be required to write off some or all of this goodwill and other intangible assets, which may cause adverse impacts on our results of operations and financial condition.
In accordance with accounting standards, goodwill and certain other indefinite-lived intangible assets that are not subject to amortization are reviewed annually or more frequently for impairment, if certain conditions exist, and may be impaired. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings, which could cause a material adverse impact on our reported results of operations and financial position.
The loss of the services of our key management and personnel could adversely affect our ability to operate our businesses.
Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete for such personnel with many other companies, in and outside our industry, government entities and other organizations. We may not be successful in retaining current personnel or in hiring or retaining qualified personnel in the future. Our failure to attract new personnel or retain existing personnel could have a material adverse effect on our businesses.
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The Sponsor Group controls and may have conflicts of interest with us in the future.
The Sponsor Group indirectly owns approximately 60% of EFH Corp.’s capital stock on a fully-diluted basis through its investment in Texas Holdings. As a result of this ownership and the Sponsor Group’s ownership in interests of the general partner of Texas Holdings, the Sponsor Group has control over decisions regarding 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.
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.
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| Item 3. | LEGAL PROCEEDINGS |
Litigation Related to Generation Facilities
In November 2010, an administrative appeal challenging the decision of the TCEQ to renew and amend Oak Grove Management Company LLC’s (Oak Grove) (a wholly-owned subsidiary of TCEH) Texas Pollutant Discharge Elimination System (TPDES) permit related to water discharges was filed by Robertson County: Our Land, Our Lives and Roy Henrichson in the Travis County, Texas District Court. Plaintiffs seek a reversal of the TCEQ’s order and a remand back to the TCEQ for further proceedings. In addition to this administrative appeal, in November 2010, two other petitions were filed in Travis County, Texas District Court by Sustainable Energy and Economic Development Coalition and Paul and Lisa Rolke, respectively, who were non-parties to the administrative hearing before the State Office of Administrative Hearings, challenging the TCEQ’s decision to renew and amend Oak Grove’s TPDES permit and asking the District Court to remand the matter to the TCEQ for further proceedings. Although 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 financial condition, results of operations or liquidity.
In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (Texarkana Division) against EFH Corp. and Luminant Generation Company LLC (a wholly-owned subsidiary of TCEH) for alleged violations of the Clean Air Act at Luminant’s Martin Lake generation facility. While we are unable to estimate any possible loss or predict the outcome of the litigation, we believe that the Sierra Club’s claims are without merit, and we intend to vigorously defend this litigation. In addition, in February 2010, the Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Big Brown generation facility. Subsequently, in December 2010, Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Monticello generation facility. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.
Regulatory Reviews
In June 2008, the EPA issued a request for information to TCEH under the EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.
Other Proceedings
In addition to the above, we are involved in various other legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on our financial position, results of operations or cash flows.
| Item 4. | (REMOVED AND RESERVED) |
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| Item 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
As a result of the Merger, EFH Corp.’s common stock is privately held, and there is no established public trading market for EFH Corp.’s common stock.
See Note 13 to Financial Statements for a description of the restrictions on EFH Corp.’s ability to pay dividends.
The number of holders of the common stock of EFH Corp. as of February 15, 2011 was 119.
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| Item 6. | SELECTED FINANCIAL DATA |
EFH CORP. AND SUBSIDIARIES
SELECTED FINANCIAL DATA
(millions of dollars, except ratios)
| Successor | Predecessor | |||||||||||||||||||||||
| Year Ended December 31, | Period from October 11, 2007 through December 31, | Period from January 1, 2007 through October 10, 2007 | Year Ended December 31, 2006 | |||||||||||||||||||||
| 2010 | 2009 | 2008 | 2007 | |||||||||||||||||||||
Operating revenues | $ | 8,235 | $ | 9,546 | $ | 11,364 | $ | 1,994 | $ | 8,044 | $ | 10,703 | ||||||||||||
Income (loss) from continuing operations | (2,812 | ) | 408 | (9,998 | ) | (1,361 | ) | 699 | 2,465 | |||||||||||||||
Income from discontinued operations, net of tax effect | — | — | — | 1 | 24 | 87 | ||||||||||||||||||
Net income (loss) | (2,812 | ) | 408 | (9,998 | ) | (1,360 | ) | 723 | 2,552 | |||||||||||||||
Net (income) loss attributable to noncontrolling interests | — | (64 | ) | 160 | — | — | — | |||||||||||||||||
Net income (loss) attributable to EFH Corp. | (2,812 | ) | 344 | (9,838 | ) | (1,360 | ) | 723 | 2,552 | |||||||||||||||
Ratio of earnings to fixed charges (a) | — | 1.24 | — | — | 2.30 | 5.11 | ||||||||||||||||||
Capital expenditures, including nuclear fuel | $ | 944 | $ | 2,545 | $ | 3,015 | $ | 716 | $ | 2,542 | $ | 2,337 | ||||||||||||
See Notes to Financial Statements.
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EFH CORP. AND SUBSIDIARIES
SELECTED FINANCIAL DATA (CONTINUED)
(millions of dollars, except ratios)
| Successor | Predecessor | |||||||||||||||||||
| As of December 31, | As of December 31, 2006 | |||||||||||||||||||
| 2010 | 2009 | 2008 | 2007 | |||||||||||||||||
Total assets | $ | 46,388 | $ | 59,662 | $ | 59,263 | $ | 64,804 | $ | 27,216 | ||||||||||
Property, plant & equipment — net | $ | 20,366 | $ | 30,108 | $ | 29,522 | $ | 28,650 | $ | 18,569 | ||||||||||
Goodwill and intangible assets | $ | 8,552 | $ | 17,192 | $ | 17,379 | $ | 27,319 | $ | 729 | ||||||||||
Capitalization | ||||||||||||||||||||
Long-term debt, less amounts due currently | $ | 34,226 | $ | 41,440 | $ | 40,838 | $ | 38,603 | $ | 10,631 | ||||||||||
EFH Corp. common stock equity | (5,990 | ) | (3,247 | ) | (3,673 | ) | 6,685 | 2,140 | ||||||||||||
Noncontrolling interests in subsidiaries | 79 | 1,411 | 1,355 | — | — | |||||||||||||||
Total | $ | 28,315 | $ | 39,604 | $ | 38,520 | $ | 45,288 | $ | 12,771 | ||||||||||
Capitalization ratios | ||||||||||||||||||||
Long-term debt, less amounts due currently | 120.9 | % | 104.6 | % | 106.0 | % | 85.2 | % | 83.2 | % | ||||||||||
EFH Corp. common stock equity | (21.2 | ) | (8.2 | ) | (9.5 | ) | 14.8 | 16.8 | ||||||||||||
Noncontrolling interests in subsidiaries | 0.3 | 3.6 | 3.5 | — | — | |||||||||||||||
Total | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | ||||||||||
Short-term borrowings | $ | 1,221 | $ | 1,569 | $ | 1,237 | $ | 1,718 | $ | 1,491 | ||||||||||
Long-term debt due currently | $ | 669 | $ | 417 | $ | 385 | $ | 513 | $ | 485 | ||||||||||
| (a) | Fixed charges exceeded “earnings” by $2.531 billion, $10.469 billion and $2.034 billion for the years ended December 31, 2010 and 2008 and for the period from October 11, 2007 through December 31, 2007, respectively. |
Note: Although 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 10 to Financial Statements. Results for 2010 were significantly impacted by a goodwill impairment charge as discussed in Note 4 to Financial Statements. 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 as discussed in Notes 4 and 5 to Financial Statements.
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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 | |||||||||||||
| 2010: | ||||||||||||||||
Operating revenues | $ | 1,999 | $ | 1,993 | $ | 2,607 | $ | 1,636 | ||||||||
Net income (loss) | 355 | (426 | ) | (2,902 | ) | 161 | ||||||||||
Net income (loss) attributable to EFH Corp. | $ | 355 | $ | (426 | ) | $ | (2,902 | ) | $ | 161 | ||||||
| First Quarter (a) | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
| 2009: | ||||||||||||||||
Operating revenues | $ | 2,139 | $ | 2,342 | $ | 2,885 | $ | 2,180 | ||||||||
Net income (loss) | 454 | (139 | ) | (54 | ) | 147 | ||||||||||
Net income attributable to noncontrolling interests | (12 | ) | (16 | ) | (26 | ) | (10 | ) | ||||||||
Net income (loss) attributable to EFH Corp. | $ | 442 | $ | (155 | ) | $ | (80 | ) | $ | 137 | ||||||
| (a) | Net income (loss) amounts include the effects of impairment charges related to goodwill (see Note 4 to Financial Statements). |
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| Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion and analysis of our financial condition and results of operations for the fiscal years ended December 31, 2010, 2009 and 2008 should be read in conjunction with Selected Financial Data and our audited consolidated financial statements and the notes to those statements.
All dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwise indicated.
Business
We are a Dallas, Texas-based holding company with operations consisting principally of our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority-owned (approximately 80%) subsidiary engaged in regulated electricity transmission and distribution operations in Texas. Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. See Notes 1 and 3 to Financial Statements for a description of the material features of these “ring-fencing” measures and for a discussion of the deconsolidation of Oncor (and its majority owner, Oncor Holdings) in 2010 as the result of a change in accounting principles.
Operating Segments
We have aligned and report our business activities as two operating segments: the Competitive Electric segment and the Regulated Delivery segment. The Competitive Electric segment is principally comprised of TCEH. The Regulated Delivery segment is comprised of Oncor Holdings and its subsidiaries. See Notes 1 and 3 to Financial Statements for discussion of the deconsolidation of Oncor Holdings and it subsidiaries in 2010.
See Note 23 to Financial Statements for further information regarding reportable business segments.
Significant Activities and Events
Natural Gas Prices and Long-Term Hedging Program — TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, the company has entered into market transactions involving natural gas-related financial instruments, and as of December 31, 2010, has effectively sold forward approximately 1.0 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 125,000 GWh at an assumed 8.0 market heat rate) for the period from January 1, 2011 through December 31, 2014 at weighted average annual hedge prices ranging from $7.19 per MMBtu to $7.80 per MMBtu.
These transactions, as well as forward power sales, have effectively hedged an estimated 62% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning January 1, 2011 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which is expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.
The long-term hedging program is comprised primarily of contracts with prices based on the New York Mercantile Exchange (NYMEX) Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. The company has hedged more than 95% of the Houston Ship Channel versus Henry Hub pricing point risk for 2011.
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The company has entered into related put and call transactions (referred to as collars), primarily for 2014, that effectively hedge natural gas prices within a range. These transactions represented 11% of the positions in the long-term hedging program as of December 31, 2010, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. The company expects to use financial instruments, including collars, in future hedging activity under the long-term hedging program.
The following table summarizes the natural gas hedges in the long-term hedging program as of December 31, 2010:
| Measure | 2011 | 2012 | 2013 | 2014 | Total | |||||||||||||||||||
Natural gas hedge volumes (a) | mm MMBtu | ~220 | ~398 | ~282 | ~110 | ~1,010 | ||||||||||||||||||
Weighted average hedge price (b) | $/MMBtu | ~7.56 | ~7.36 | ~7.19 | ~7.80 | — | ||||||||||||||||||
Weighted average market price (c) | $/MMBtu | ~4.55 | ~5.08 | ~5.33 | ~5.49 | — | ||||||||||||||||||
| (a) | Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity (i.e., delta position) of the derivatives. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 110 million MMBtu in 2014. |
| (b) | Weighted average hedge prices are based on NYMEX Henry Hub prices of forward natural gas sales positions in the long-term hedging program (excluding the impact of offsetting purchases for rebalancing and pricing point basis transactions). Where collars are reflected, sales price represents the collar floor price. |
| (c) | Based on NYMEX Henry Hub prices. |
Changes in the fair value of the instruments in the long-term hedging program are being recorded as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities in the statement of income, which has and could continue to result in significant volatility in reported net income. Based on the size of the long-term hedging program as of December 31, 2010, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to $1.0 billion in pretax unrealized mark-to-market gains or losses.
Unrealized mark-to-market net gains related to the long-term hedging program are as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Effect of natural gas market price changes on open positions | $ | 2,317 | $ | 1,857 | $ | 2,483 | ||||||
Reversals of previously recorded amounts on positions settled | (1,152 | ) | (750 | ) | 104 | |||||||
Total unrealized effect (pre-tax) | $ | 1,165 | $ | 1,107 | $ | 2,587 | ||||||
The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $3.143 billion and $1.978 billion as of December 31, 2010 and 2009, respectively. See discussion below under “Results of Operations” for realized net gains from hedging activities, which amounts are largely related to the long-term hedging program.
Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains or losses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices and will in this context be viewed as having resulted in an opportunity cost.
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The significant cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program reflects declining forward market natural gas prices. Forward natural gas prices have generally trended downward since mid-2008 as shown in the table of forward NYMEX Henry Hub natural gas prices below. While the long-term hedging program is designed to mitigate the effect on earnings of low wholesale 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 the correlated effect in ERCOT on wholesale power prices could have a material adverse impact on the overall profitability of our generation assets for periods in which we have less significant hedge positions (i.e., beginning in 2013). In addition, a continuation or worsening of these market conditions would limit our ability to hedge our wholesale electricity revenues at sufficient price levels to support our interest payments and debt maturities and could adversely impact our ability to refinance the TCEH Revolving Credit Facility that matures in October 2013 and/or our substantial long-term debt that matures in 2014.
Also see discussion below regarding the goodwill impairment charge recorded in the third quarter 2010.
| Forward Market Prices for Calendar Year ($/MMBtu) (a) | ||||||||||||||||||||
Date | 2010 (b) | 2011 | 2012 | 2013 | 2014 | |||||||||||||||
June 30, 2008 | $ | 11.24 | $ | 10.78 | $ | 10.74 | $ | 10.90 | $ | 11.12 | ||||||||||
September 30, 2008 | $ | 8.58 | $ | 8.54 | $ | 8.41 | $ | 8.30 | $ | 8.30 | ||||||||||
December 31, 2008 | $ | 7.13 | $ | 7.31 | $ | 7.23 | $ | 7.15 | $ | 7.15 | ||||||||||
March 31, 2009 | $ | 5.93 | $ | 6.67 | $ | 6.96 | $ | 7.11 | $ | 7.18 | ||||||||||
June 30, 2009 | $ | 6.06 | $ | 6.89 | $ | 7.16 | $ | 7.30 | $ | 7.43 | ||||||||||
September 30, 2009 | $ | 6.21 | $ | 6.87 | $ | 7.00 | $ | 7.06 | $ | 7.17 | ||||||||||
December 31, 2009 | $ | 5.79 | $ | 6.34 | $ | 6.53 | $ | 6.67 | $ | 6.84 | ||||||||||
March 31, 2010 | $ | 4.27 | $ | 5.34 | $ | 5.79 | $ | 6.07 | $ | 6.36 | ||||||||||
June 30, 2010 | $ | 4.82 | $ | 5.34 | $ | 5.68 | $ | 5.89 | $ | 6.10 | ||||||||||
September 30, 2010 | $ | 3.94 | $ | 4.44 | $ | 5.07 | $ | 5.29 | $ | 5.42 | ||||||||||
December 31, 2010 | $ | — | $ | 4.55 | $ | 5.08 | $ | 5.33 | $ | 5.49 | ||||||||||
| (a) | Based on NYMEX Henry Hub prices. |
| (b) | For September 30, 2010, June 30, 2010 and March 31, 2010, natural gas prices for 2010 represent the average of forward prices for October through December, July through December and April through December, respectively. |
As of December 31, 2010, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility – see discussion below under “Financial Condition — Liquidity and Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.
See discussion below under “Key Risks and Challenges,” specifically, “Substantial Leverage, Uncertain Financial Markets and Liquidity Risk” and “Natural Gas Price and Market Heat Rate Exposure.”
Impairment of Goodwill— In the third quarter 2010, 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, 2010.
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 4 to Financial Statements and “Application of Critical Accounting Policies” below for more information on goodwill impairment charges.
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Liability Management Program — As of December 31, 2010, EFH Corp. and its subsidiaries (excluding Oncor and its subsidiaries) had $35.5 billion aggregate principal amount of long-term debt outstanding. The majority of that amount matures during the period 2014 to 2017, and the TCEH Revolving Credit Facility matures in October 2013. In October 2009, we implemented a liability management program focused on improving our balance sheet by reducing debt and extending debt maturities through debt exchanges, repurchases and issuances. Activities under the liability management program do not include debt issued by Oncor or its subsidiaries.
The following table details our debt exchange and repurchase activities in the year ended December 31, 2010 and since the inception of our liability management program in October 2009 (debt amounts are principal amounts):
| Year Ended December 31, 2010 | Since Inception | |||||||||||||||
Security | Debt Acquired | Debt Issued/ Cash Paid | Debt Acquired | Debt Issued/ Cash Paid | ||||||||||||
EFH Corp 10.875% Notes due 2017 | $ | 1,472 | $ | — | $ | 1,641 | $ | — | ||||||||
EFH Corp. Toggle Notes due 2017 | 2,420 | — | 2,432 | — | ||||||||||||
EFH Corp. 5.55% Series P Senior Notes due 2014 | 549 | — | 566 | — | ||||||||||||
EFH Corp. 6.50% Series Q Senior Notes due 2024 | — | — | 10 | — | ||||||||||||
EFH Corp. 6.55% Series R Senior Notes due 2034 | — | — | 6 | — | ||||||||||||
TCEH 10.25% Notes due 2015 | 1,692 | — | 1,835 | — | ||||||||||||
TCEH Toggle Notes due 2016 | 751 | — | 751 | — | ||||||||||||
Term Loans under the TCEH Senior Secured Facilities due 2014 | 20 | — | 20 | — | ||||||||||||
EFH Corp. and EFIH 9.75% Notes due 2019 | — | — | — | 256 | ||||||||||||
EFH Corp 10% Notes due 2020 | — | 561 | — | 561 | ||||||||||||
EFIH 10% Notes due 2020 | — | 2,180 | — | 2,180 | ||||||||||||
TCEH 15% Notes due 2021 | — | 1,221 | — | 1,221 | ||||||||||||
Cash paid, including use of proceeds from debt issuances in 2010 (a) | — | 1,042 | — | 1,042 | ||||||||||||
Total | $ | 6,904 | $ | 5,004 | $ | 7,261 | $ | 5,260 | ||||||||
| (a) | Includes $95 million of the proceeds from the issuance of $500 million principal amount of EFH Corp. 10% Notes in January 2010 and $290 million of the proceeds from the issuance of $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes in October 2010. |
Since inception, the transactions resulted in the capture of $2 billion of debt discount and aggregate projected interest savings (pre-tax) over five years of approximately $1.2 billion, the majority of which represents interest on the EFH Corp. and TCEH Toggle Notes.
No liability management transactions were completed in 2011 through February 15.
See Note 11 to Financial Statements for further discussion of the transactions completed under our liability management program.
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Wholesale Market Design – Nodal Market — In accordance with a rule adopted by the PUCT in 2003, ERCOT developed a new wholesale market, using a stakeholder process, designed to assign congestion costs to the market participants causing the congestion. The nodal market design was implemented December 1, 2010. Under this new market design, ERCOT:
| • | establishes nodes, which are metered locations across the ERCOT grid, for purposes of more granular price determination; |
| • | operates a voluntary “day-ahead electricity market” for forward sales and purchases of electricity and other related transactions, in addition to the existing “real-time market” that primarily functions to balance power consumption and generation; |
| • | establishes hub trading prices, which represent the average of certain node prices within four major geographic regions, at which participants can hedge or trade power under bilateral contracts; |
| • | establishes pricing for load-serving entities based on weighted-average node prices within new geographical load-zones, and |
| • | provides congestion revenue rights, which are instruments auctioned by ERCOT that allow market participants to hedge price differences between settlement points. |
ERCOT previously had a zonal wholesale market structure consisting of four geographic zones. The new location-based congestion-management market is referred to as a “nodal” market because wholesale pricing differs across the various nodes on the transmission grid instead of across the geographic zones. There are over 500 nodes in the ERCOT market. The nodal market design was implemented in conjunction with transmission improvements designed to reduce current congestion. We are fully certified to participate in both the “day-ahead” and “real-time markets.” Additionally, all of our operational and mothballed generation assets and our qualified scheduling entities are certified and operate in the nodal market. While the initial implementation of the nodal market has not had a material impact on our profitability, we cannot predict the ultimate impact of the market design on our operations or financial results, and it could ultimately have an adverse impact on the profitability and value of our competitive business and/or our liquidity, particularly if such change ultimately results in lower revenue due to lower wholesale power prices, increased costs to service end-user electricity demand or increased collateral posting requirements with ERCOT. The opening of the nodal market resulted in an increase of approximately $200 million in the amount of letters of credit posted with ERCOT to support our market participation.
As discussed above, the nodal market design includes the establishment of a “day-ahead market” and hub trading prices to facilitate hedging and trading of electricity by participants. Under the previous zonal market, volumes under 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 in 2011 will be materially less than amounts reported in prior periods.
TCEH Interest Rate Swap Transactions— As of December 31, 2010, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $15.80 billion principal amount of its senior secured debt maturing from 2011 to 2014. Swaps related to an aggregate $500 million principal amount of debt expired in 2010, and no swaps were entered into in 2010. Taking into consideration these swap transactions, 13% of our total long-term debt portfolio as of December 31, 2010 was exposed to variable interest rate risk. As of December 31, 2010, TCEH also entered into interest rate basis swap transactions, which further reduce the fixed (through swaps) borrowing costs, related to an aggregate of $15.20 billion principal amount of senior secured debt, including swaps entered into in 2010 related to $2.55 billion principal amount of debt. Swaps related to an aggregate $3.60 billion principal amount of debt expired in 2010. We may enter into additional interest rate hedges from time to time.
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Unrealized mark-to-market net gains and losses related to all TCEH interest rate swaps, which are reported in interest expense and related charges, totaled $207 million in net losses for the year ended December 31, 2010 and $696 million in net gains for the year ended December 31, 2009. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.419 billion and $1.212 billion as of December 31, 2010 and 2009, respectively, of which $105 million and $194 million (both pre-tax), respectively, was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. See discussion in Note 11 to Financial Statements regarding interest rate swap transactions.
Texas Generation Facilities Development —TCEH has completed a program to develop three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in Texas with a total estimated capacity of approximately 2,200 MW. The Sandow and first Oak Grove units achieved substantial completion (as defined in the EPC agreement) in the fourth quarter 2009, and the second Oak Grove unit achieved substantial completion (as defined in the EPC agreement) in the second quarter 2010. 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.
Idling of Natural Gas-Fueled Units — In December 2010, after receiving approval from ERCOT, we retired eight previously mothballed natural gas-fueled units totaling 2,633 MW of capacity (2,777 MW installed nameplate capacity). We also retired an additional natural gas-fueled unit with 112 MW of capacity (115 MW installed nameplate capacity) in December 2010 upon expiration of an RMR (operational standby) agreement (discussed below) related to the unit. No impairment was recorded as a result of the retirements. In September 2010, after receiving approval from ERCOT, we mothballed (idled) four of our natural gas-fueled units totaling 1,856 MW of capacity (1,933 MW installed nameplate capacity). In 2009 we retired 10 units totaling 2,114 MW of capacity (2,226 MW installed nameplate capacity), mothballed three units totaling 1,081 MW capacity (1,135 MW installed nameplate capacity) and entered into RMR agreements with ERCOT for two units totaling 627 MW capacity (655 MW installed nameplate capacity). Upon expiration of the RMR agreements in December 2010, we retired the unit discussed above and mothballed the other unit.
As of December 31, 2010, TCEH’s operational fleet of natural gas-fueled generation facilities, which are generally used as peaking resources, consists of 14 units totaling 2,187 MW installed nameplate capacity, excluding eight units operated for unaffiliated parties and four mothballed units.
Global Climate Change and Other Environmental Matters —See Items 1 and 2 “Business and Properties – Environmental Regulations and Related Considerations” for discussion of global climate change and various other environmental matters and their effects on the company.
Oncor Technology Initiatives— Oncor continues to invest in technology initiatives that include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs. Oncor’s plans provide for the full deployment of over three million advanced meters to all residential and most non-residential retail electricity customers in Oncor’s service area. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits.
As of December 31, 2010, Oncor has installed approximately 1,514,000 advanced digital meters, including approximately 854,000 during the year ended December 31, 2010. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $360 million as of December 31, 2010. Oncor expects to complete installations of the remaining approximately 1.5 million advanced meters by the end of 2012.
Oncor Matters with the PUCT— See discussion of these matters, including the construction of CREZ-related transmission lines, below under “Regulatory Matters.”
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KEY RISKS AND CHALLENGES
Following is a discussion of key risks and challenges facing management and the initiatives currently underway to manage such challenges. These matters involve risks that could have a material adverse effect on our results of operations, liquidity or financial condition.
Substantial Leverage, Uncertain Financial Markets and Liquidity Risk
Our substantial leverage, resulting in large part from debt incurred to finance the Merger, requires significant cash flows to be dedicated to interest and principal payments and could adversely affect our ability to raise additional capital to fund operations, limit our ability to react to changes in the economy, our industry or our business, and expose us to interest rate risk to the extent not hedged. Principal amounts of short-term borrowings and long-term debt, including amounts due currently, totaled $36.721 billion as of December 31, 2010. Taking into consideration interest-rate swap transactions, as of December 31, 2010 approximately 87% of our total long-term debt portfolio is subject to fixed interest rates, at a weighted average interest rate of 8.9%. Interest payments on long-term debt in 2011 are expected to total approximately $2.750 billion, and principal payments are expected to total $651 million.
While we believe our cash on hand and cash flow from operations combined with availability under existing credit facilities provide sufficient liquidity to fund current and projected expenses and capital requirements for 2011 (see “Financial Condition – Liquidity and Capital Resources” section below), 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, 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 long-term hedging program in “Financial Condition – Liquidity and Capital Resources” and discussion of potential impact of legislative rulemakings on the OTC derivatives market in “Significant Activities and Events – Financial Services Reform Legislation.”
In addition, as discussed above under “Significant Activities and Events – Natural Gas Prices and Long-Term Hedging Program,” a continuation or worsening of low forward natural gas prices (and the related low wholesale electricity prices in ERCOT) could also limit our ability to hedge our wholesale electricity revenues at sufficient price levels to support our interest payments and debt maturities, result in further declines in the value of our baseload generation assets and adversely impact our efforts to refinance our substantial debt as discussed immediately below.
The TCEH Revolving Credit Facility matures in October 2013, and a substantial amount of our long-term debt matures in the period from 2014 through 2017. We are focused on improving the balance sheet and expect to opportunistically look for ways to reduce the amount, and extend the maturity, of our outstanding debt. Progress to date on this initiative includes the debt exchanges, issuances and repurchases completed in 2010 and 2009 discussed above under “Significant Activities and Events – Liability Management Program” and the August 2009 amendment to the Credit Agreement governing the TCEH Senior Secured Facilities that provided additional flexibility in restructuring debt obligations. See Note 11 to Financial Statements for additional discussion of these transactions.
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.
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Natural Gas Price and Market Heat-Rate Exposure
Wholesale electricity prices in the ERCOT market generally move with the price of natural gas because marginal demand for electricity supply is generally met with natural gas-fueled generation facilities. Historically the price of natural gas has fluctuated due to changes in industrial demand, supply availability, weather effects and other economic and market factors and such prices have been very volatile in recent years. Since 2005, forward natural gas prices ranged from above $13 per MMBtu to below $4 per MMBtu. More recent declines in forward natural gas prices reflect discovery and increased drilling of shale gas deposits combined with lingering demand weakness associated with the economic recession. The wholesale market price of electricity divided by the market price of natural gas represents the market heat rate. Market heat rate movements also affect wholesale electricity prices. Market heat rate can be affected by a number of factors including the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity.
In contrast to 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 baseload generation assets, which provided the substantial majority of supply volumes in 2010, increase or decrease in value as natural gas prices and market heat rates rise or fall, respectively, because of the effect on wholesale electricity prices in ERCOT.
With the exposure to variability of natural gas prices, retail sales price management and hedging activities are critical to the profitability of the business and maintaining consistent cash flow levels.
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. |
As discussed above in “Significant Activities and Events,” we have implemented a long-term hedging program to mitigate the risk of lower wholesale electricity prices due to declines in natural gas prices.
The following sensitivity table provides estimates of the potential impact (in $ millions) of movements in natural gas and certain other commodity prices and market heat rates on realized pre-tax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH’s unhedged position and forward prices as of December 31, 2010, which for natural gas reflects estimates of electricity generation less amounts hedged through the long-term natural gas hedging program and amounts under existing wholesale and retail sales contracts. On a rolling twelve-month basis, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.
| Balance 2011(a) | 2012 | 2013 | 2014 | |||||||||||||
$1.00/MMBtu change in gas price (b) | $ | ~5 | $ | ~80 | $ | ~305 | $ | ~490 | ||||||||
0.1/MMBtu/MWh change in market heat rate (c) | $ | ~4 | $ | ~32 | $ | ~44 | $ | ~46 | ||||||||
$1.00/gallon change in diesel fuel price | $ | — | $ | ~1 | $ | ~48 | $ | ~40 | ||||||||
| (a) | Balance of 2011 is from February 1, 2011 through December 31, 2011 |
| (b) | Assumes conversion of electricity positions based on an approximate 8.0 market heat rate with natural gas being on the margin 75% to 90% of the time (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated). |
| (c) | Based on Houston Ship Channel natural gas prices as of December 31, 2010. |
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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. 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. We mitigate market heat rate risk through retail and wholesale electricity sales contracts and shorter-term market heat rate hedging transactions. We evaluate opportunities to mitigate market heat rate risk over extended periods through longer-term electricity sales contracts where practical considering pricing, credit, liquidity and related factors.
On an ongoing basis, we will continue monitoring our overall commodity risks and seek to balance our portfolio based on our desired level of exposure to natural gas prices and market heat rates and potential changes to our operational forecasts of overall generation and consumption (which is also subject to volatility resulting from customer churn, weather, economic and other factors) in our native and growth business. Portfolio balancing may include the execution of incremental transactions, including heat rate hedges, the unwinding of existing transactions and the substitution of natural gas hedges with commitments for the sale of electricity at fixed prices. As a result, commodity price exposures and their effect on earnings could materially change from time to time.
Competitive Retail Markets and Customer Retention
Competitive retail activity in Texas has resulted in retail customer churn. Our total retail customer counts rose 2% in 2008 but declined 3% in 2009 and 6% in 2010. Based upon 2010 results discussed below in “Results of Operations – Competitive Electric Segment,” a 1% decline in residential customers would result in a decline in annual revenues of approximately $40 million. In responding to the competitive landscape in the ERCOT marketplace, we are focusing on the following key initiatives:
| • | Maintaining competitive pricing initiatives as evidenced by price reductions on most residential service plans; |
| • | Profitably growing the retail customer base by actively competing for new and existing customers in areas in Texas open to competition. The customer retention strategy remains focused on continuing to implement initiatives to deliver world-class customer service and improve the overall customer experience; |
| • | Establishing TXU Energy as the most innovative retailer in the Texas market by continuing to develop tailored product offerings to meet customer needs. TXU Energy plans to invest $100 million over the five-year period beginning in 2008 (including $39 million invested through 2010) in retail initiatives aimed at helping consumers conserve energy and other demand-side management initiatives that are intended to moderate consumption and reduce peak demand for electricity, and |
| • | Focusing business market initiatives largely on programs targeted to retain the existing highest-value customers and to recapture customers who have switched REPs. Initiatives include maintaining and continuously refining a disciplined contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and marketing efforts and to more effectively deploy the direct-sales force. Tactical programs put into place include improved customer service, aided by a new customer management system implemented in 2009, new product price/service offerings and a multichannel approach for the small business market. |
Volatile Energy Prices and Regulatory Risk
Natural gas prices rose to unprecedented levels in the latter part of 2005, reflecting a world-wide increase in energy prices compounded by hurricane-related infrastructure damage. The related rise in electricity prices elevated public awareness of energy costs and dampened customer demand. Natural gas prices remain subject to events that create price volatility, and while not reaching 2005 levels, forward natural gas prices rose substantially in 2007 and part of 2008 before falling in the second half of 2008 through most of 2010. Sustained high energy prices and/or ongoing price volatility also creates a risk for regulatory and/or legislative intervention with the mechanisms that govern the competitive wholesale and retail markets in ERCOT. 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 long-term 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.
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Financial Services Reform Legislation
In July 2010, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Financial Reform Act) was enacted. The primary purposes of the Financial Reform Act are, among other things, to address systemic risk in the financial system; to establish a Bureau of Consumer Financial Protection with broad powers to enforce consumer protection laws and promulgate rules against unfair, deceptive or abusive practices; to enhance regulation of the derivatives markets, including the requirement for central clearing of over-the-counter derivative instruments and additional capital and margin requirements for certain derivative market participants; and to implement a number of new corporate governance requirements for companies with listed or, in some cases, publicly-traded securities. While the legislation is broad and detailed, substantial portions of the legislation are currently under rulemakings by federal governmental agencies to implement the standards set out in the legislation and adopt new standards. As a result, the full scope and effect of the legislation will likely not be known for several years.
Title VII of the Financial Reform Act provides for the regulation of the over-the-counter (OTC) derivatives market. The Financial Reform Act generally requires OTC derivatives (including the types of asset-backed OTC derivatives that 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 continue to closely monitor the rulemakings and any other potential legislative and regulatory changes and work with regulators and legislators, providing them information on our operations, the types of transactions in which we engage, our concerns regarding potential regulatory impacts, market characteristics and related matters.
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 continue to evaluate existing requirements and consider proposals for 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 12 to Financial Statements for discussion of “Litigation Related to Generation Facilities,” “Regulatory Reviews” and “Environmental Contingencies.”)
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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 adversely affected by the enactment of any legislation, regulation or judicial action that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes on entities that produce GHG emissions, or that establishes federal renewable energy portfolio standards. For example, federal, state or regional legislation or regulation addressing global climate change could result in 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.”
Exposures Related to Nuclear Asset Outages
Our nuclear assets are comprised of two generation units at Comanche Peak, each with an installed nameplate capacity of 1,150 MW. The Comanche Peak plant represents approximately 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, 2010) to be approximately $2 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 12 to Financial Statements.
The inherent complexities and related regulations associated with operating nuclear generation facilities result in environmental, regulatory and financial risks. The operation of nuclear generation facilities is complex and subject to continuing review and regulation by the NRC, covering, among other things, operations, maintenance, emergency planning, security, and environmental and safety protection. The NRC may implement changes in regulations that result in increased capital or operating costs, and it may require extended outages, modify, suspend or revoke operating licenses and impose fines for failure to comply with its existing regulations and the provisions of the Atomic Energy Act. In addition, an unplanned outage at another nuclear generation facility could result in the NRC taking action to shut down the Comanche Peak plant as a precautionary measure.
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.
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. This risk is substantially mitigated by the ring-fencing measures as described in Note 1 to Financial Statements.
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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 and adversely 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.
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.
Purchase Accounting
In 2007, the Merger was accounted for under purchase accounting, whereby the purchase price of the transaction was allocated to our identifiable assets acquired and liabilities assumed based upon their fair values. The estimates of the fair values recorded were determined based on the principles in accounting standards related to the determination of fair value (see Note 15 to Financial Statements) and reflect significant assumptions and judgments. Material valuation inputs for long-lived assets and liabilities included forward electricity and natural gas price curves and market heat rates, discount rates, nonperformance risk adjustments related to liabilities, retail customer attrition rates, generation plant operating and construction costs and asset lives. The valuations reflected considerations unique to the competitive wholesale power market in ERCOT as well as our assets. For example, the valuation of the baseload generation facilities considered our lignite fuel reserves and mining capabilities.
The results of the purchase price allocation included an increase in the total carrying value of our baseload generation plants and the recording of intangible assets related to the retail customer base, the TXU Energy trade name and emission credits. Further, commodity and other contracts not already subject to fair value accounting were valued, and amounts representing favorable or unfavorable contracts (versus market conditions as of the date of the Merger) were recorded as intangible assets or liabilities, respectively. Management believes all material intangible assets were identified. See Note 4 to Financial Statements for details of the intangible assets recorded.
With respect to Oncor, the realization of its assets and settlement of its liabilities are largely subject to cost-based regulatory rate-setting processes. Accordingly, the historical carrying values of a majority of Oncor’s assets and liabilities were deemed to represent fair values. See discussion in Note 24 to Financial Statements regarding adjustments to the carrying values of Oncor’s regulatory asset and related long-term debt.
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The excess of the purchase price over the estimated fair values of the net assets acquired was recorded as goodwill. The goodwill amount recorded upon finalization of purchase accounting totaled $23.2 billion. Management believes the drivers of the goodwill amount included the incremental value of the future cash flow potential of the baseload generation facilities, including facilities under construction, over the values assigned to those assets under purchase accounting rules, considering the market-pricing mechanisms and growth potential in the ERCOT market, as well as the value derived from the scale of the retail business. Management also believes that the goodwill reflected the value of the relatively stable, long-lived cash flows of the regulated business, considering the constructive regulatory environment and market growth potential. In accordance with accounting guidance related to goodwill and other intangible assets, goodwill is not amortized to net income, but is required to be tested for impairment at least annually. This guidance requires that goodwill be assigned to “reporting units,” which management has determined to be the Competitive Electric segment and the Regulated Delivery segment, which are almost entirely comprised of TCEH and Oncor, respectively. The assignment of goodwill was based on the relative estimated enterprise values of the operations as of the date of the Merger. Goodwill amounts assigned totaled $18.3 billion to the Competitive Electric segment and $4.9 billion to the Regulated Delivery segment. None of this goodwill balance is being deducted for tax purposes.
In the third quarter 2010, we recorded a goodwill impairment charge related to the Competitive Electric segment totaling $4.1 billion. In the first quarter 2009 and fourth quarter 2008, we recorded goodwill impairment charges totaling $8.950 billion, of which $8.070 billion related to the Competitive Electric segment. The $90 million charge in the first quarter 2009 resulted from the completion of the previously estimated fair value calculations supporting the initial $8.860 billion goodwill impairment charge that was recorded in the fourth quarter 2008. See discussion immediately below under “Impairment of Goodwill and Other Long-Lived Assets.”
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 (as was the case for the natural gas-fueled generation assets in 2008 discussed below). For our baseload generation assets, another possible indication would be an expected long-term decline in natural gas prices and/or market heat rates. 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 possible 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.
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The determination of enterprise value involves a number of assumptions and estimates. We use a combination of three fair value inputs to estimate enterprise values of our reporting units: internal discounted cash flow analyses (income approach), comparable company values and any recent pending and/or completed relevant transactions. The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, generation plant performance and retail sales volume trends. Another key variable in the income approach is the discount rate, or weighted average cost of capital. The determination of the discount rate takes into consideration the capital structure, debt ratings and current debt yields of comparable companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry. Enterprise value estimates based on comparable company values involve using trading multiples of EBITDA of those selected companies to derive appropriate multiples to apply to the EBITDA of the reporting units. This approach requires an estimate, using historical acquisition data, of an appropriate control premium to apply to the reporting unit values calculated from such multiples. Critical judgments include the selection of comparable companies and the weighting of the three value inputs in developing the best estimate of enterprise value.
The 2010 annual impairment testing performed as of December 1, 2010 for goodwill and intangible assets with indefinite useful lives in accordance with accounting guidance resulted in no impairment. The goodwill testing determined that the carrying value of the Competitive Electric segment exceeded its estimated fair value (enterprise value), so the estimated enterprise value of the segment was compared to the estimated fair values of its operating assets and liabilities. This additional testing indicated that the recorded goodwill amount did not exceed the estimated implied goodwill amount, and thus no additional goodwill impairment was indicated beyond the charge recorded in the third quarter 2010 as discussed immediately below. Key variables in the tests included forward natural gas prices, electricity prices, market heat rates and discount rates, assumptions regarding each of which could have a significant effect on valuations. Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.
See Note 4 to Financial Statements for a discussion of the goodwill impairment charges of $4.1 billion recorded in 2010 and $8.950 billion recorded largely in 2008. The total of $13.050 billion in impairment charges represented almost 60% of the goodwill balance resulting from purchase accounting for the Merger and reflected a decline of approximately 20% in the estimated enterprise value as of December 1, 2010 from the indicated value at the October 2007 Merger date. The impairment in 2010 reflected the estimated effect of lower wholesale power prices on the enterprise value of 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. Also see Note 4 to Financial Statements for discussion of the impairment charge of $481 million ($310 million after-tax) related to the trade name intangible asset recorded in the fourth quarter 2008. The estimated fair value of this intangible asset is based on an assumed royalty methodology. Impairment charges totaling $501 million in 2008 related to environmental allowances and credits are also discussed in Note 4 to Financial Statements.
In 2008, we recorded an impairment charge of $229 million ($147 million after-tax) related to our natural gas-fueled generation facilities. The natural gas-fueled generation units are generally operated to meet peak demands for electricity, and the facilities were tested for impairment as an asset group. See Note 5 to Financial Statements for a discussion of the impairment. The estimated impairment was based on numerous judgments including forecasted production, forward prices of natural gas and electricity, overall generation availability in ERCOT and ERCOT grid congestion. See “Business – Significant Activities and Events” for discussion of natural gas-fueled units mothballed (idled) or retired in 2009 consistent with the factors that resulted in the impairment.
Derivative Instruments and Mark-to-Market Accounting
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.
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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 15 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 at the inception of the contract, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. “Normal” purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting if the election as normal is made. Hedge accounting designations are made with the intent to match the accounting recognition of the contract’s financial performance to that of the transaction the contract is intended to hedge.
Under hedge accounting, changes in fair value of instruments designated as cash flow hedges are recorded in other comprehensive income with an offset to derivative assets and liabilities to the extent the change in value is effective; that is, it mirrors the offsetting change in fair value of the forecasted hedged transaction. Changes in value that represent ineffectiveness of the hedge are recognized in net income immediately, and the effective portion of changes in fair value initially recorded in other comprehensive income are recognized in net income in the period that the hedged transactions are recognized. Although as of December 31, 2010, 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 long-term hedging program that were previously designated as cash flow hedges were dedesignated as allowed under accounting standards related to derivative instruments and hedging activities, and subsequent changes in their fair value are being marked-to-market in net income. In addition, in August 2008, interest rate swap transactions in effect at that time were dedesignated as cash flow hedges in accordance with accounting standards, and subsequent changes in their fair value are being marked-to-market in net income. See further discussion of the long-term hedging program and interest rate swap transactions under “Business – Significant Activities and Events.”
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The following tables provide the effects on both net income and other comprehensive income of mark-to-market accounting for those derivative instruments that we have determined to be subject to fair value measurement under accounting standards related to derivative instruments and hedging activities.
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Amounts recognized in net income (loss) (after-tax): | ||||||||||||
Unrealized net gains on positions marked-to-market in net income (a) | $ | 1,257 | $ | 1,573 | $ | 518 | ||||||
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the period (a) | (607 | ) | (333 | ) | 25 | |||||||
Unrealized ineffectiveness net losses on positions accounted for as cash flow hedges | — | — | (3 | ) | ||||||||
Reversals of previously recognized unrealized net losses related to cash flow hedge positions settled in the period | 1 | 1 | — | |||||||||
Total | $ | 651 | $ | 1,241 | $ | 540 | ||||||
Amounts recognized in other comprehensive income (after-tax): | ||||||||||||
Net losses in fair value of positions accounted for as cash flow hedges | $ | — | $ | (20 | ) | $ | (183 | ) | ||||
Net losses on cash flow hedge positions recognized in net income to offset hedged transactions | 59 | 130 | 122 | |||||||||
Total | $ | 59 | $ | 110 | $ | (61 | ) | |||||
| (a) | Amounts for 2010, 2009 and 2008 include $785 million, $788 million and $1.503 billion in net after-tax gains related to commodity positions, respectively, and $135 million in net after-tax losses, $452 million in net after-tax gains and $960 million in net after-tax losses related to interest rate swaps, respectively. |
The effect of mark-to-market and hedge accounting for derivatives on the balance sheet is as follows:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
Commodity contract assets | $ | 4,705 | $ | 3,860 | ||||
Commodity contract liabilities | $ | (1,608 | ) | $ | (2,146 | ) | ||
Interest rate swap assets | $ | 98 | $ | 64 | ||||
Interest rate swap liabilities | $ | (1,544 | ) | $ | (1,306 | ) | ||
Net accumulated other comprehensive loss included in shareholders’ equity (amounts after tax) | $ | (69 | ) | $ | (128 | ) | ||
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 15 to Financial Statements.
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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 and electricity derivative instruments entered into for hedging purposes, securities associated with the nuclear decommissioning trust, and interest rate swaps intended to fix and/or lower interest payments on long-term debt. Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Level 2 valuations are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences. Level 2 inputs include:
| • | quoted prices for similar assets or liabilities in active markets; |
| • | quoted prices for identical or similar assets or liabilities in markets that are not active; |
| • | inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals, and |
| • | inputs that are derived principally from or corroborated by observable market data by correlation or other means. |
Examples of Level 2 valuation inputs utilized include over-the-counter broker quotes and quoted prices for similar assets or liabilities that are corroborated by correlation or through statistical relationships between different price curves. For example, certain physical power derivatives are executed for a particular location at specific time periods that might not have active markets; however, an active market might exist for such derivatives for a different time period at the same location. We utilize correlation techniques to compare prices for inputs at both time periods to provide a basis to value the non-active derivative. (See Note 15 to Financial Statements for additional discussion of how broker quotes are utilized.)
Level 3 valuations generally apply to our more complex long-term power purchases and sales agreements, including longer-term wind and other power purchase and sales contracts and certain natural gas positions (collars) in the long-term hedging program. Level 3 valuations use largely unobservable inputs, with little or no supporting market activity, and assets and liabilities are classified as Level 3 if such inputs are significant to the fair value determination. 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.
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Level 3 assets totaled $401 million and $350 million as of December 31, 2010 and 2009, respectively, and represented approximately 8% of the assets measured at fair value, or less than 1% of total assets in both years. Level 3 liabilities totaled $59 million and $269 million as of December 31, 2010 and 2009, respectively, and represented approximately 2% and 8%, respectively, of the liabilities measured at fair value, or less than 1% of total liabilities.
Valuations of several of 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, 2010, a $5.00 per MWh change in electricity price assumptions across unobservable inputs would cause an approximate $5 million change in net Level 3 assets. A 10% change in coal price assumptions across unobservable inputs would cause an approximate $1 million change in net Level 3 assets. See Note 15 to Financial Statements for additional information about fair value measurements, including a table presenting the changes in Level 3 assets and liabilities for the twelve months ended December 31, 2010, 2009 and 2008.
Variable Interest Entities
A variable interest entity (VIE) is an entity with which 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.
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 $297 million, $546 million and $505 million as of December 31, 2010, 2009 and 2008, 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 $108 million, $113 million and $81 million for the years ended December 31, 2010, 2009 and 2008, respectively.
Litigation contingencies also may require significant judgment in estimating amounts to accrue. 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, 2010. See Item 3, “Legal Proceedings” for discussion of major litigation.
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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. See Notes 1, 7 and 8 to Financial Statements for discussion of income tax matters.
Depreciation and Amortization
Depreciation expense related to generation facilities is based on the estimates of fair value and economic useful lives as determined in the application of purchase accounting described above. The accuracy of these estimates directly affects the amount of depreciation expense. If future events indicate that the estimated lives are no longer appropriate, depreciation expense will be recalculated prospectively from the date of such determination based on the new estimates of useful lives.
The estimated remaining lives range from 22 to 59 years for the lignite/coal- and nuclear-fueled generation units.
Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 4 to Financial Statements for additional information.
Defined Benefit Pension Plans and OPEB Plans
We provide pension benefits based on either a traditional defined benefit formula or a cash balance formula and also provide certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from our company. Reported costs of providing noncontributory defined pension benefits and OPEB are dependent upon numerous factors, assumptions and estimates.
PURA provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility. These costs are associated with Oncor’s active and retired employees, as well as active and retired personnel engaged in other EFH Corp. activities related to their service prior to the deregulation and disaggregation of our business effective January 1, 2002. Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs reflected in Oncor’s approved (by the PUCT) billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Accordingly, Oncor defers (principally as a regulatory asset or property) additional pension and OPEB costs consistent with PURA. Amounts deferred are ultimately subject to regulatory approval.
Benefit costs are impacted by actual employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.
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In accordance with accounting rules, changes in benefit obligations associated with these factors may not be immediately recognized as costs in the income statement, but are recognized in future years over the remaining average service period of plan participants. As such, significant portions of benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. Pension and OPEB costs as determined under applicable accounting rules are summarized in the following table:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Pension costs | $ | 100 | $ | 44 | $ | 21 | ||||||
OPEB costs | 80 | 70 | 58 | |||||||||
Total benefit costs | $ | 180 | $ | 114 | $ | 79 | ||||||
Less amounts expensed by Oncor (and not consolidated) | (37 | ) | — | — | ||||||||
Less amounts deferred principally as a regulatory asset or property by Oncor | (93 | ) | (66 | ) | (42 | ) | ||||||
Net amounts recognized as expense | $ | 50 | $ | 48 | $ | 37 | ||||||
Discount rate (a) | 5.90 | % | 6.90 | % | 6.55 | % | ||||||
| ||||||||||||
| (a) | Discount rate for OPEB was 6.85% in 2009. |
See Note 20 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 2010 Pension and OPEB Costs | |||
Discount rate – 1% increase | $ | (52 | ) | |
Discount rate – 1% decrease | $ | 62 | ||
Expected return on assets – 1% increase | $ | (22 | ) | |
Expected return on assets – 1% decrease | $ | 22 | ||
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RESULTS OF OPERATIONS
Effects of Change in Wholesale Electricity Market
As discussed above under “Significant Activities and Events,” the nodal wholesale market design implemented by ERCOT in December 2010 resulted in operational changes that facilitate hedging and trading of power. As part of ERCOT’s transition to a nodal wholesale market, volumes under nontrading bilateral purchase and sales contracts are no longer scheduled as physical power with ERCOT. As a result of these changes in market operations, reported wholesale revenues and purchased power costs in 2011 will be materially less than amounts reported in prior periods. Effective with the nodal market implementation, if volumes delivered to 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.
Pro Forma Consolidated Financial Results
As the result of deconsolidation of Oncor Holdings effective 2010, the results of Oncor Holdings are reflected in the 2010 consolidated statement of income as equity in earnings of unconsolidated subsidiary (net of tax) instead of separately as revenues and expenses as they are shown for periods prior to January 1, 2010. The following pro forma results for the year ended December 31, 2009 are presented to provide for a meaningful comparison, along with the analyses on the following pages, of consolidated operating results in consideration of the deconsolidation of Oncor Holdings as discussed in Notes 1 and 3 to Financial Statements.
| Year Ended | Year Ended December 31, 2009 | |||||||||||||||
| December 31, 2010 | As Reported | Pro Forma Adjustments (a) | Pro Forma | |||||||||||||
| (millions of dollars) | ||||||||||||||||
Operating revenues | $ | 8,235 | $ | 9,546 | $ | (1,632 | ) | $ | 7,914 | |||||||
Fuel, purchased power costs and delivery fees | (4,371 | ) | (2,878 | ) | (1,058 | ) | (3,936 | ) | ||||||||
Net gain from commodity hedging and trading activities | 2,161 | 1,736 | — | 1,736 | ||||||||||||
Operating costs | (837 | ) | (1,598 | ) | 908 | (690 | ) | |||||||||
Depreciation and amortization | (1,407 | ) | (1,754 | ) | 557 | (1,197 | ) | |||||||||
Selling, general and administrative expenses | (751 | ) | (1,068 | ) | 193 | (875 | ) | |||||||||
Franchise and revenue-based taxes | (106 | ) | (359 | ) | 250 | (109 | ) | |||||||||
Impairment of goodwill | (4,100 | ) | (90 | ) | — | (90 | ) | |||||||||
Other income | 2,051 | 204 | (50 | ) | 154 | |||||||||||
Other deductions | (31 | ) | (97 | ) | 34 | (63 | ) | |||||||||
Interest income | 10 | 45 | (1 | ) | 44 | |||||||||||
Interest expense and related charges | (3,554 | ) | (2,912 | ) | 306 | (2,606 | ) | |||||||||
Income (loss) before income taxes and equity in earnings of unconsolidated subsidiaries | (2,700 | ) | 775 | (493 | ) | 282 | ||||||||||
Income tax (expense) benefit | (389 | ) | (367 | ) | 173 | (194 | ) | |||||||||
Equity in earnings of unconsolidated subsidiaries (net of tax) | 277 | — | 256 | 256 | ||||||||||||
Net income (loss) | (2,812 | ) | 408 | (64 | ) | 344 | ||||||||||
Net income attributable to noncontrolling interests | — | (64 | ) | 64 | — | |||||||||||
Net income (loss) attributable to EFH Corp. | $ | (2,812 | ) | $ | 344 | $ | — | $ | 344 | |||||||
| (a) | All pro forma adjustments relate to Oncor Holdings and result in the presentation of the investment in Oncor Holdings under the equity method of accounting for the year ended December 31, 2009. |
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Consolidated Financial Results — Year Ended December 31, 2010 Compared to Pro Forma Year Ended December 31, 2009
See comparison of results of the Competitive Electric segment for discussion of variances in: operating revenues; fuel, purchased power costs and delivery fees; net gain (loss) from commodity hedging and trading activities, operating costs; depreciation and amortization, and franchise and revenue-based taxes.
SG&A expenses decreased $124 million, or 14%, to $751 million in 2010 driven by $66 million in lower transition costs associated with outsourced support services and the retail customer information system implemented in 2009, $18 million in lower employee compensation-related expense and $12 million of accounts receivable securitization program fees that are reported as interest expense and related charges in 2010 (see Notes 10 and 19 to Financial Statements).
See Note 4 to Financial Statements for discussion of the $4.1 billion impairment of goodwill recorded in the Competitive Electric segment in 2010. The $90 million impairment of goodwill recorded in 2009 largely related to the Competitive Electric segment and resulted from the completion of fair value calculations supporting a goodwill impairment charge recorded in the fourth quarter 2008 as discussed in Note 4 to Financial Statements.
Other income totaled $2.051 billion in 2010 and $154 million in 2009. Debt extinguishment gains totaled $1.814 billion and $87 million in 2010 and 2009, respectively (see discussion of debt exchanges and repurchases in Note 11 to Financial Statements). The 2010 amount also included a $116 million gain on termination of a long-term power sales contract, a $44 million gain on sale of land and related water rights and a $37 million gain on sale of interests in a natural gas gathering pipeline business. The 2009 amount included $23 million of income arising from the reversal of a use tax accrual recorded in purchase accounting related to periods prior to the Merger, which was triggered by a state ruling in the third quarter 2009, and $11 million of income arising from the reversal of exit liabilities recorded in purchase accounting due to sooner than expected transition of outsourcing services (see Note 19 to Financial Statements).
Other deductions totaled $31 million in 2010 and $63 million in 2009. The 2009 amount included an impairment charge of $34 million related to land expected to be sold. See Note 9 to Financial Statements for details of other income and deductions.
Interest income decreased $34 million, or 77%, to $10 million in 2010 reflecting lower interest on $465 million in collateral under a funding arrangement, due to settlement of the arrangement as described in Note 17 to Financial Statements.
Interest expense and related charges increased $948 million to $3.554 billion in 2010 reflecting a $207 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $696 million net gain in 2009 and a $214 million decrease in capitalized interest due to completion of new generation facility construction activities, partially offset by $97 million in decreased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges, reflecting values attributed to earlier periods, as well as lower interest expense resulting from reduced debt under the liability management program as described above under “Significant Activities and Events.” Also, see Note 24 to Financial Statements.
Income tax expense totaled $389 million in 2010 compared to $194 million in 2009. Excluding the effects of the $4.1 billion and $90 million nondeductible goodwill impairment charges in 2010 and 2009, respectively, the effective tax rates were 27.8% in 2010 and 52.2% in 2009. The decrease in the effective tax rate in 2010 was driven by lower interest accrued related to uncertain tax positions, including the effect of a $146 million reversal of previously accrued interest (see Note 7 to Financial Statements) net of the effect of an $8 million deferred tax charge related to the Patient Protection and Affordable Care Act (see Note 8 to Financial Statements).
Equity in earnings of unconsolidated subsidiaries (net of tax) increased $21 million to $277 million in 2010 driven by improved earnings of Oncor, which reflected higher revenues, primarily due to weather effects and rate increases, and the effect of a $25 million write off of regulatory assets in 2009, partially offset by increased noncash expenses recognized as a result of the PUCT’s final order in the June 2008 rate review.
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The consolidated net loss of $2.812 billion in 2010 represented a $3.156 billion decrease in results.
| • | Results in the Competitive Electric segment decreased $4.094 billion to a loss of $3.463 billion. |
| • | Earnings from the Regulated Delivery segment increased $21 million to $277 million as discussed above. |
| • | Corporate and Other net income totaled $374 million in 2010 compared to net expenses of $543 million in 2009. The amounts in 2010 and 2009 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The change of $917 million reflected $670 million in higher debt extinguishment gains in 2010, the $121 million Corporate and Other portion of the 2010 reversal of accrued interest on uncertain tax positions discussed above, $68 million in lower SG&A expense primarily reflecting lower transition costs associated with outsourced support services and costs allocated to the competitive operations effective 2010 and a $20 million goodwill impairment charge in 2009, partially offset by an $8 million deferred tax charge due to the implementation of the Patient Protection and Affordable Care Act in 2010 (all amounts after-tax). |
Consolidated Financial Results — Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Reference is made to comparisons of results by business segment following the discussion of consolidated results. The business segment comparisons provide additional detail and quantification of items affecting financial results.
Operating revenues decreased $1.818 billion, or 16%, to $9.546 billion in 2009.
| • | Operating revenues in the Competitive Electric segment decreased $1.876 billion, or 19%, to $7.911 billion. |
| • | Operating revenues in the Regulated Delivery segment increased $110 million, or 4%, to $2.690 billion. |
| • | Net intercompany sales eliminations increased $52 million, reflecting Oncor’s higher distribution revenues from REP subsidiaries of TCEH. |
Fuel, purchased power costs and delivery fees decreased $1.717 billion, or 37%, to $2.878 billion in 2009, driven by lower purchased power costs. See discussion below in the analysis of Competitive Electric segment results of operations.
Net gains from commodity hedging and trading activities totaled $1.736 billion in 2009 and $2.184 billion in 2008. Results in 2009 and 2008 included unrealized mark-to-market net gains totaling $1.277 billion and $2.281 billion, respectively, driven by the effect of lower forward market prices of natural gas on the value of positions in the long-term hedging program. See discussion below in the analysis of Competitive Electric segment results of operations.
Operating costs increased $95 million, or 6%, to $1.598 billion in 2009.
| • | Operating costs in the Competitive Electric segment increased $16 million, or 2%, to $693 million. |
| • | Operating costs in the Regulated Delivery segment increased $80 million, or 10%, to $908 million. |
Depreciation and amortization increased $144 million, or 9%, to $1.754 billion in 2009.
| • | Depreciation and amortization in the Competitive Electric segment increased $80 million, or 7%, to $1.172 billion. |
| • | Depreciation and amortization in the Regulated Delivery segment increased $65 million, or 13%, to $557 million. |
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SG&A expenses increased $111 million, or 12%, to $1.068 billion in 2009.
| • | SG&A expenses in the Competitive Electric segment increased $59 million, or 9%, to $741 million. |
| • | SG&A expenses in the Regulated Delivery segment increased $30 million, or 18%, to $194 million. |
| • | Corporate and Other SG&A expenses increased $22 million, or 20%, to $133 million driven by higher transition costs associated with outsourced support services. |
See Note 4 to Financial Statements for discussion of the $90 million and $8.860 billion impairments of goodwill in 2009 and 2008, respectively.
Other income totaled $204 million in 2009 and $80 million in 2008, including $39 million and $44 million, respectively, in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. The 2009 amount also included an $87 million debt extinguishment gain (see discussion of debt exchanges in Note 11 to Financial Statements), $23 million of income arising from the reversal of a use tax accrual recorded in purchase accounting related to periods prior to the Merger, which was triggered by a state ruling in the third quarter of 2009, and $21 million of income arising from the reversal of exit liabilities recorded in purchase accounting due to sooner than expected transition of outsourcing services (see Note 19 to Financial Statements). The 2008 amount also included a $21 million net insurance recovery for damage to certain mining equipment.
Other deductions totaled $97 million in 2009 and $1.301 billion in 2008. The 2009 amount included an impairment charge of $34 million related to land expected to be sold within the next 12 months and a $25 million write off of regulatory assets as discussed in Note 24 to Financial Statements. The 2008 amount included impairment charges of $501 million related to NOx and SO2 environmental allowances intangible assets and $481 million related to trade name intangible assets, both discussed in Note 4 to Financial Statements, $229 million in impairment charges related to the natural gas-fueled generation facilities and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 9 to Financial Statements for details of other income and deductions.
Interest income increased $18 million, or 67%, to $45 million driven by interest on $465 million in collateral under a funding arrangement described in Note 17 to Financial Statements.
Interest expense and related charges decreased $2.023 billion to $2.912 billion in 2009 reflecting a $696 million unrealized mark-to-market net gain related to interest rate swaps in 2009 as compared to a $1.477 billion net loss in 2008, which was partially offset by $118 million in increased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges and a $34 million decrease in capitalized interest. See Note 24 to Financial Statements.
Income tax expense totaled $367 million in 2009 compared to an income tax benefit of $471 million in 2008. The effective rate on income in 2009 was 47.4%, and the effective rate on a loss in 2008 was 4.5%. The increase in the rate reflects the impacts of nondeductible goodwill impairments of $90 million in 2009 and $8.860 billion in 2008, which increased the effective rate by 5.0 percentage points in 2009 and decreased the effective rate by 24.8 percentage points in 2008. The increase also reflects the effect of interest accrued for uncertain tax positions, which increased the rate on income in 2009 and decreased the rate on a loss in 2008.
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Reflecting the goodwill and other impairment charges recorded in 2008, after tax-results improved $10.406 billion to $408 million in net income in 2009.
| • | After-tax results in the Competitive Electric segment improved $9.560 billion to $631 million in net income in 2009. |
| • | After-tax results in the Regulated Delivery segment improved $806 million to $320 million in net income in 2009. |
| • | Corporate and Other net expenses totaled $543 million in 2009 and $583 million in 2008. The amounts in 2009 and 2008 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The after-tax decrease of $40 million reflected the debt extinguishment gain of $57 million and $16 million in interest income related to the collateral discussed above, partially offset by a $20 million goodwill impairment charge and the $14 million increase in SG&A expense as discussed above. |
Non-GAAP Earnings Measures
In communications with investors, we use a non-GAAP earnings measure that reflects adjustments to earnings reported in accordance with US GAAP in order to review underlying operating performance. These adjusting items, which are generally noncash, consist of unrealized mark-to-market gains and losses, impairment charges, debt extinguishment gains and other charges, credits or gains that are unusual or nonrecurring. All such items and related amounts are disclosed in our annual report on Form 10-K and quarterly reports on Form 10-Q. Our communications with investors also reference “Adjusted EBITDA,” which is a non-GAAP measure used in calculation of ratios in covenants of certain of our debt securities (see “Financial Condition – Liquidity and Capital Resources – Financial Covenants, Credit Rating Provisions and Cross Default Provisions” below).
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Competitive Electric Segment
Financial Results
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Operating revenues | $ | 8,235 | $ | 7,911 | $ | 9,787 | ||||||
Fuel, purchased power costs and delivery fees | (4,371 | ) | (3,934 | ) | (5,600 | ) | ||||||
Net gain from commodity hedging and trading activities | 2,161 | 1,736 | 2,184 | |||||||||
Operating costs | (837 | ) | (693 | ) | (677 | ) | ||||||
Depreciation and amortization | (1,380 | ) | (1,172 | ) | (1,092 | ) | ||||||
Selling, general and administrative expenses | (722 | ) | (741 | ) | (682 | ) | ||||||
Franchise and revenue-based taxes | (106 | ) | (108 | ) | (110 | ) | ||||||
Impairment of goodwill | (4,100 | ) | (70 | ) | (8,000 | ) | ||||||
Other income | 903 | 59 | 34 | |||||||||
Other deductions | (21 | ) | (68 | ) | (1,274 | ) | ||||||
Interest income | 91 | 64 | 61 | |||||||||
Interest expense and related charges | (2,957 | ) | (1,946 | ) | (4,010 | ) | ||||||
Income (loss) before income taxes | (3,104 | ) | 1,038 | (9,379 | ) | |||||||
Income tax (expense) benefit | (359 | ) | (407 | ) | 450 | |||||||
Net income (loss) | $ | (3,463 | ) | $ | 631 | $ | (8,929 | ) | ||||
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Competitive Electric Segment
Sales Volume and Customer Count Data
| Year Ended December 31, | 2010 | 2009 | ||||||||||||||||||
| 2010 | 2009 | 2008 | % Change | % Change | ||||||||||||||||
Sales volumes: | ||||||||||||||||||||
Retail electricity sales volumes – (GWh): | ||||||||||||||||||||
Residential | 28,208 | 28,046 | 28,135 | 0.6 | (0.3 | ) | ||||||||||||||
Small business (a) | 8,042 | 7,962 | 7,363 | 1.0 | 8.1 | |||||||||||||||
Large business and other customers | 15,339 | 14,573 | 13,945 | 5.3 | 4.5 | |||||||||||||||
Total retail electricity | 51,589 | 50,581 | 49,443 | 2.0 | 2.3 | |||||||||||||||
Wholesale electricity sales volumes (b) | 51,359 | 42,320 | 46,743 | 21.4 | (9.5 | ) | ||||||||||||||
Total sales volumes | 102,948 | 92,901 | 96,186 | 10.8 | (3.4 | ) | ||||||||||||||
Average volume (kWh) per residential customer (c) | 15,532 | 14,855 | 14,780 | 4.6 | 0.5 | |||||||||||||||
Weather (North Texas average) – percent of normal (d): | ||||||||||||||||||||
Cooling degree days | 108.9 | % | 98.1 | % | 107.3 | % | 11.0 | (8.6 | ) | |||||||||||
Heating degree days | 116.6 | % | 105.8 | % | 98.3 | % | 10.2 | 7.6 | ||||||||||||
Customer counts: | ||||||||||||||||||||
Retail electricity customers (end of period and in thousands) (e): | ||||||||||||||||||||
Residential | 1,771 | 1,862 | 1,914 | (4.9 | ) | (2.7 | ) | |||||||||||||
Small business (a) | 217 | 262 | 275 | (17.2 | ) | (4.7 | ) | |||||||||||||
Large business and other customers | 20 | 23 | 25 | (13.0 | ) | (8.0 | ) | |||||||||||||
Total retail electricity customers | 2,008 | 2,147 | 2,214 | (6.5 | ) | (3.0 | ) | |||||||||||||
| (a) | Customers with demand of less than 1 MW annually. |
| (b) | Includes net amounts related to sales and purchases of balancing energy in the “real-time market.” |
| (c) | Calculated using average number of customers for the period. |
| (d) | Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). Normal is defined as the average over a 10-year period. |
| (e) | Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number of meters does not reflect the number of individual customers. The year ended December 31, 2008 reflects reclassification of 18 thousand meters from residential to small business to conform to current presentation. |
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Competitive Electric Segment
Revenue and Commodity Hedging and Trading Activities
| Year Ended December 31, | 2010 % Change | 2009 % Change | ||||||||||||||||||
| 2010 | 2009 | 2008 | ||||||||||||||||||
Operating revenues: | ||||||||||||||||||||
Retail electricity revenues: | ||||||||||||||||||||
Residential | $ | 3,663 | $ | 3,806 | $ | 3,782 | (3.8 | ) | 0.6 | �� | ||||||||||
Small business (a) | 1,052 | 1,164 | 1,099 | (9.6 | ) | 5.9 | ||||||||||||||
Large business and other customers | 1,211 | 1,261 | 1,447 | (4.0 | ) | (12.9 | ) | |||||||||||||
Total retail electricity revenues | 5,926 | 6,231 | 6,328 | (4.9 | ) | (1.5 | ) | |||||||||||||
Wholesale electricity revenues (b) (c) | 2,005 | 1,383 | 3,115 | 45.0 | (55.6 | ) | ||||||||||||||
Amortization of intangibles (d) | 16 | 5 | (36 | ) | — | — | ||||||||||||||
Other operating revenues | 288 | 292 | 380 | (1.4 | ) | (23.2 | ) | |||||||||||||
Total operating revenues | $ | 8,235 | $ | 7,911 | $ | 9,787 | 4.1 | (19.2 | ) | |||||||||||
Net gain from commodity hedging and trading activities: | ||||||||||||||||||||
Unrealized net gains from changes in fair value | $ | 2,162 | $ | 1,741 | $ | 2,290 | 24.2 | (24.0 | ) | |||||||||||
Unrealized net losses representing reversals of previously recognized fair values of positions settled in the current period | (1,009 | ) | (464 | ) | (9 | ) | — | — | ||||||||||||
Realized net gains (losses) on settled positions | 1,008 | 459 | (97 | ) | — | — | ||||||||||||||
Total gain | $ | 2,161 | $ | 1,736 | $ | 2,184 | 24.5 | (20.5 | ) | |||||||||||
| (a) | Customers with demand of less than 1 MW annually. |
| (b) | Upon settlement of physical derivative power sales and purchase contracts that are marked-to-market in net income, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result, these line item amounts include a noncash component, which the company considers “unrealized.” (The offsetting differences between contract and market prices are reported in net gain from commodity hedging and trading activities.) These amounts are as follows: |
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Reported in revenues | $ | (28 | ) | $ | (166 | ) | $ | 42 | ||||
Reported in fuel and purchased power costs | 96 | 114 | 6 | |||||||||
Net gain (loss) | $ | 68 | $ | (52 | ) | $ | 48 | |||||
| (c) | Includes net amounts related to sales and purchases of balancing energy in the “real-time market.” |
| (d) | Represents amortization of the intangible net asset value of retail and wholesale power sales agreements resulting from purchase accounting. |
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Competitive Electric Segment
Production, Purchased Power and Delivery Cost Data
| Year Ended December 31, | 2010 % Change | 2009 % Change | ||||||||||||||||||
| 2010 | 2009 | 2008 | ||||||||||||||||||
Fuel, purchased power costs and delivery fees ($ millions): | ||||||||||||||||||||
Nuclear fuel | $ | 159 | $ | 121 | (f) | $ | 95 | 31.4 | 27.4 | |||||||||||
Lignite/coal | 910 | 670 | 640 | 35.8 | 4.7 | |||||||||||||||
Total baseload fuel | 1,069 | 791 | 735 | 35.1 | 7.6 | |||||||||||||||
Natural gas fuel and purchased power (a) | 1,502 | 1,224 | 2,881 | 22.7 | (57.5 | ) | ||||||||||||||
Amortization of intangibles (b) | 161 | 285 | (f) | 318 | (43.5 | ) | (10.4 | ) | ||||||||||||
Other costs | 187 | 202 | 351 | (7.4 | ) | (42.5 | ) | |||||||||||||
Fuel and purchased power costs | 2,919 | 2,502 | 4,285 | 16.7 | (41.6 | ) | ||||||||||||||
Delivery fees (c) | 1,452 | 1,432 | 1,315 | 1.4 | 8.9 | |||||||||||||||
Total | $ | 4,371 | $ | 3,934 | $ | 5,600 | 11.1 | (29.8 | ) | |||||||||||
Fuel and purchased power costs (which excludes generation facilities operating costs) per MWh: | ||||||||||||||||||||
Nuclear fuel | $ | 7.89 | $ | 5.98 | (f) | $ | 4.92 | 31.9 | 21.5 | |||||||||||
Lignite/coal (d) | $ | 19.19 | $ | 16.47 | $ | 15.80 | 16.5 | 4.2 | ||||||||||||
Natural gas fuel and purchased power | $ | 52.37 | $ | 44.36 | $ | 81.99 | 18.1 | (45.9 | ) | |||||||||||
Delivery fees per MWh | $ | 28.06 | $ | 28.09 | $ | 26.33 | (0.1 | ) | 6.7 | |||||||||||
Production and purchased power volumes (GWh): | ||||||||||||||||||||
Nuclear | 20,208 | 20,104 | 19,218 | 0.5 | 4.6 | |||||||||||||||
Lignite/coal | 54,775 | 45,684 | 44,923 | 19.9 | 1.7 | |||||||||||||||
Total baseload generation | 74,983 | 65,788 | 64,141 | 14.0 | 2.6 | |||||||||||||||
Natural gas-fueled generation | 1,648 | 2,447 | 4,122 | (32.7 | ) | (40.6 | ) | |||||||||||||
Purchased power (e) | 26,317 | 24,666 | 27,923 | 6.7 | (11.7 | ) | ||||||||||||||
Total energy supply volumes | 102,948 | 92,901 | 96,186 | 10.8 | (3.4 | ) | ||||||||||||||
Baseload capacity factors: | ||||||||||||||||||||
Nuclear | 100.3 | % | 100.0 | % | 95.2 | % | 0.3 | 5.0 | ||||||||||||
Lignite/coal | 82.2 | % | 86.5 | % | 87.6 | % | (5.0 | ) | (1.3 | ) | ||||||||||
Total baseload | 86.6 | % | 90.3 | % | 89.8 | % | (4.1 | ) | 0.6 | |||||||||||
| (a) | See note (b) on previous page. |
| (b) | Represents amortization of the intangible net asset values of emission credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting. |
| (c) | Includes delivery fee charges from Oncor that prior to 2010 were eliminated in consolidation. |
| (d) | Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs. |
| (e) | Includes amounts related to line loss and power imbalances. |
| (f) | Reflects reclassification to correct amortization. |
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Competitive Electric Segment – Financial Results – Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Operating revenues increased $324 million, or 4%, to $8.235 billion in 2010.
Wholesale electricity revenues increased $622 million, or 45%, to $2.005 billion in 2010. A 21% increase in wholesale electricity sales volumes, reflecting production from the new generation units and increased sales to third-party REPs, increased revenues by $332 million. An 8% increase in average wholesale electricity prices, reflecting higher natural gas prices at the time the underlying contracts were executed, increased revenues by $149 million. The balance of the revenue increase reflected lower unrealized losses in 2010 related to physical derivative commodity sales contracts as discussed in footnote (b) to the “Revenue and Commodity Hedging and Trading Activities” table above.
Retail electricity revenues decreased $305 million, or 5%, to $5.926 billion and reflected the following:
| • | Lower average pricing decreased revenues by $429 million reflecting declines in both the business and residential markets. Lower average pricing is reflective of competitive activity in a lower wholesale power price environment and a change in business customer mix. |
| • | A 2% increase in sales volumes increased revenues by $124 million reflecting increases in both the business and residential markets. A 4% increase in business markets sales volumes reflected a change in customer mix resulting from contracts executed with new customers. Residential sales volumes increased 1% reflecting higher average consumption driven by colder winter weather and hotter summer weather, partially offset by a decline in residential customer counts. |
Fuel, purchased power costs and delivery fees increased $437 million, or 11%, to $4.371 billion in 2010. Higher purchased power costs contributed $255 million to the increase and reflected increased planned generation unit outages and higher retail demand, as well as increased prices driven by the effect of higher natural gas prices at the time the underlying contracts were executed. Other factors contributing to the increase included $126 million in higher lignite/coal costs at existing plants, reflecting higher purchased coal transportation and commodity costs, $114 million in increased lignite fuel costs related to production from the new generation units, a $39 million increase in nuclear fuel expense reflecting increased uranium and conversion costs, a $23 million increase in natural gas and fuel oil costs driven by higher prices, $20 million in higher delivery fees, reflecting increased retail sales volumes and tariffs, and an $18 million decrease in unrealized gains related to physical derivative commodity purchase contracts. These increases were partially offset by $124 million in lower amortization of the intangible net asset values (including the stepped-up value of nuclear fuel) resulting from purchase accounting, which reflected expiration of commodity contracts and consumption of the nuclear fuel.
Overall baseload generation production increased 14% in 2010 driven by production from the new generation units. Nuclear production increased 1%, and existing lignite/coal-fueled generation decreased 2% driven by increased economic backdown.
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Following is an analysis of amounts reported as net gain from commodity hedging and trading activities for the years ended December 31, 2010 and 2009, which totaled $2.161 billion and $1.736 billion, respectively:
Year Ended December 31, 2010 —Unrealized mark-to-market net gains totaling $1.153 billion included:
| • | $1.157 billion in net gains related to hedge positions, which includes $2.133 billion in net gains from changes in fair value, driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $976 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and |
| • | $4 million in net losses related to trading positions, which includes $29 million in net gains from changes in fair value, and $33 million in net losses that represent reversals of previously recorded net gains on positions settled in the period. |
Realized net gains totaling $1.008 billion included:
| • | $961 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and |
| • | $47 million in net gains related to trading positions. |
Year Ended December 31, 2009 —Unrealized mark-to-market net gains totaling $1.277 billion included:
| • | $1.260 billion in net gains related to hedge positions, which includes $1.719 billion in net gains from changes in fair value, driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $459 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and |
| • | $17 million in net gains related to trading positions, which includes $22 million in net gains from changes in fair value, and $5 million in net losses that represent reversals of previously recorded net gains on positions settled in the period. |
Realized net gains totaling $459 million included:
| • | $449 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and |
| • | $10 million in net gains related to trading positions. |
Unrealized gains and losses that are related to physical derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $68 million in net gains in 2010 and $52 million in net losses in 2009.
Operating costs increased $144 million, or 21%, to $837 million in 2010. The increase reflected $90 million in incremental expense related to the new generation units. The balance of the increase was driven by installation and maintenance of emissions control equipment at the existing lignite/coal-fueled generation facilities and higher maintenance costs at both the nuclear and existing lignite/coal-fueled facilities reflecting timing and scope of project work.
Depreciation and amortization increased $208 million, or 18%, to $1.380 billion in 2010. The increase reflected $162 million in incremental expense related to the new generation units and associated mining operations. The balance of the increase was driven by equipment additions.
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SG&A expenses decreased $19 million, or 3%, to $722 million in 2010. The decrease reflected:
| • | $31 million in lower transition costs associated with outsourced services and the retail customer information management system implemented in 2009; |
| • | $16 million in lower employee compensation-related expense in 2010; |
| • | $12 million of accounts receivable securitization program fees that are reported in 2010 as interest expense and related charges (see Note 10 to Financial Statements), and |
| • | $8 million in lower bad debt expense, |
partially offset by $46 million of costs allocated from corporate in 2010, principally fees paid to the Sponsor Group.
See Note 4 to Financial Statements for discussion of the $4.1 billion impairment of goodwill recorded in 2010 and of the $70 million impairment of goodwill recorded in 2009 that resulted from the completion of fair value calculations supporting a goodwill impairment charge recorded in the fourth quarter of 2008.
Other income totaled $903 million in 2010 and $59 million in 2009. Other income in 2010 included debt extinguishment gains of $687 million, a $116 million gain on termination of a power sales contract, a $44 million gain on the sale of land and related water rights and a $37 million gain associated with the sale of interests in a natural gas gathering pipeline business. The 2009 amount included a $23 million reversal of a use tax accrual, an $11 million reversal of exit liabilities recorded in connection with the termination of outsourcing arrangements and $25 million in several individually immaterial items. Other deductions totaled $21 million in 2010 and $68 million in 2009. The 2010 amount included several individually immaterial items. The 2009 amount included $34 million in charges for the impairment of land expected to be sold, $7 million in severance charges and other individually immaterial miscellaneous expenses. See Note 9 to Financial Statements for additional details.
Interest income increased $27 million, or 42%, to $91 million in 2010 reflecting higher notes receivable balances from affiliates.
Interest expense and related charges increased by $1.011 billion, or 52%, to $2.957 billion in 2010 reflecting a $207 million unrealized mark-to-market net loss related to interest rate swaps in 2010 compared to a $696 million net gain in 2009 and a $214 million decrease in capitalized interest due to completion of new generation facility construction activities, partially offset by a $97 million decrease in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges.
Income tax expense totaled $359 million in 2010 compared to $407 million in 2009. Excluding the $4.1 billion and $70 million nondeductible goodwill impairment charges in 2010 and 2009, respectively, the effective tax rates were 36.0% and 36.7%, respectively.
Results for the segment decreased $4.094 billion in 2010 to a loss of $3.463 billion reflecting the $4.1 billion goodwill impairment charge and increased interest expense, partially offset by debt extinguishment gains and an increase in net gains from commodity hedging and trading activities.
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Competitive Electric Segment – Financial Results – Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Operating revenues decreased $1.876 billion, or 19%, to $7.911 billion in 2009.
Wholesale electricity revenues decreased $1.732 billion, or 56%, to $1.383 billion in 2009 as compared to 2008. Volatility in wholesale revenues and purchased power costs reflects movements in natural gas prices, as lower natural gas prices in 2009 drove a 46% decline in average wholesale electricity sales prices. Reported wholesale revenues and purchased power costs also reflect changes in volumes of bilateral contracting activity entered into to mitigate the effects of demand volatility and congestion. Results in 2009 reflect lower demand volatility and a decline in congestion, which drove a 10% decline in wholesale sales volumes. Net purchases of balancing electricity from ERCOT totaling $80 million in 2009 and $214 million in 2008, which were previously disclosed separately, are now included within wholesale electricity revenues.
Retail electricity revenues declined $97 million, or 2%, to $6.231 billion and reflected the following:
| • | Lower average pricing contributed $242 million to the revenue decline. The change in average pricing reflected lower average contracted business rates driven by lower wholesale electricity prices, partially offset by higher average pricing in the residential and non-contract business markets resulting from advanced meter surcharges as well as customer mix. |
| • | Retail sales volume growth of 2% increased revenues by $145 million. Volumes rose in the business markets driven by changes in customer mix resulting from contracting activity, but declined slightly in the residential market driven by a 3% decrease in customers. |
Other operating revenues decreased $88 million, or 23%, to $292 million in 2009 due to lower natural gas prices and lower volumes on sales of natural gas to industrial customers.
The change in operating revenues also reflected a $41 million decrease in amortization of intangible assets arising from purchase accounting reflecting expiration of retail sales contracts.
Fuel, purchased power costs and delivery fees decreased $1.666 billion, or 30%, to $3.934 billion in 2009. This decrease was driven by lower purchased power costs due to the effect of lower natural gas prices, decreased demand volatility and reduced congestion as discussed above regarding wholesale revenues. Lower costs of replacement power during unplanned generation unit repair outages contributed to improved margin. Other factors contributing to lower fuel and purchased power costs included lower natural gas-fueled generation and lower related fuel costs ($374 million), the effect of lower natural gas prices on natural gas purchased for sale to industrial customers ($116 million) and lower amortization of intangible assets arising from purchase accounting ($26 million).
Overall baseload generation production increased 3% in 2009 reflecting a 5% increase in nuclear production and a 2% increase in lignite/coal-fueled production. The increase in nuclear production, which reflects two refueling outages in 2008 compared to one refueling outage in 2009 and investments to increase generation capacity, resulted in improved margin. The increase in lignite/coal-fueled production reflected generation from the new units placed in service in the fourth quarter 2009, partially offset by generation reductions during certain periods when power could be purchased in the wholesale market at prices below production costs, which was largely due to lower natural gas prices and higher wind generation availability.
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Following is an analysis of amounts reported as net gain from commodity hedging and trading activities for the years ended December 31, 2009 and 2008, which totaled $1.736 billion and $2.184 billion, respectively:
Year Ended December 31, 2009 —Unrealized mark-to-market net gains totaling $1.277 billion included:
| • | $1.260 billion in net gains related to hedge positions, which includes $1.719 billion in net gains from changes in fair value, driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $459 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and |
| • | $17 million in net gains related to trading positions, which includes $22 million in net gains from changes in fair value and $5 million in net losses that represent reversals of previously recorded net gains on positions settled in the period. |
Realized net gains totaling $459 million included:
| • | $449 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and |
| • | $10 million in net gains related to trading positions. |
Year Ended December 31, 2008— Unrealized mark-to-market net gains totaling $2.281 billion included:
| • | $2.324 billion in net gains related to hedge positions, which includes $2.282 billion in net gains from changes in fair value and $42 million in net gains that represent reversals of previously recorded fair values of positions settled in the period; |
| • | $68 million in “day one” net losses related to large hedge positions (see Note 17 to Financial Statements), and |
| • | $25 million in net gains related to trading positions, which includes $76 million in net gains from changes in fair value and $51 million in net losses that represent reversals of previously recorded fair values of positions settled in the period. |
Realized net losses totaling $97 million included:
| • | $177 million in net losses related to hedge positions that primarily offset hedged electricity revenues and fuel and purchased power costs recognized in the period, and |
| • | $80 million in net gains related to trading positions. |
Unrealized gains and losses that are related to physically settled derivative commodity contracts and are reported as revenues and purchased power costs, as required by accounting rules, totaled $52 million in net losses in 2009 and $48 million in net gains in 2008.
Operating costs increased $16 million, or 2%, to $693 million in 2009 driven by $28 million in costs related to the new lignite-fueled generation facilities. The change also reflected $19 million in higher maintenance costs incurred during planned and unplanned lignite-fueled generation unit outages in 2009 that was more than offset by the $31 million effect of two planned nuclear generation unit outages in 2008 as compared to one in 2009.
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Depreciation and amortization increased $80 million, or 7%, to $1.172 billion in 2009. The increase was driven by $39 million in higher amortization expense related to the intangible asset representing retail customer relationships recorded in purchase accounting and $24 million due to the placement in service of two new generation units and related mining assets. Increased lignite generation unit depreciation as a result of normal capital additions as well as adjustments to useful lives of components was partially offset by lower natural gas generation unit depreciation resulting from an impairment in 2008.
SG&A expenses increased $59 million, or 9%, to $741 million in 2009. The increase reflected $36 million in higher retail bad debt expense, reflecting higher delinquencies due to delays in final bills and disconnects resulting from a system conversion, customer losses and general economic conditions. The increase also reflected higher employee related expenses, the implementation of a new retail customer information management system and the transition of certain previously outsourced customer operations, partially offset by $13 million in lower fees associated with the sale of receivables program.
See Note 4 to Financial Statements for discussion of the impairments of goodwill of $70 million in 2009 and $8.0 billion in 2008.
Other income totaled $59 million in 2009 and $34 million in 2008. The 2009 amount included a $23 million reversal of a use tax accrual, an $11 million reversal of exit liabilities recorded in connection with the termination of outsourcing arrangements (see Note 19 to Financial Statements), a $6 million fee received related to an interest rate swap/commodity hedge derivative agreement, $5 million in royalty income and $5 million in sales/use tax refunds. The 2008 amount included an insurance recovery of $21 million and $4 million in royalty income. See Note 9 to Financial Statements for more details.
Other deductions totaled $68 million in 2009 and $1.274 billion in 2008. The 2009 amount included $34 million in charges for the impairment of land expected to be sold within the next 12 months, $7 million in charges for severance and other individually immaterial miscellaneous expenses. The 2008 amount included $501 million in impairment charges related to NOx and SO2 environmental allowances intangible assets and $481 million related to trade name intangible assets, both discussed in Note 4 to Financial Statements, $229 million in impairment charges related to the natural gas-fueled generation facilities discussed in Note 5 to Financial Statements and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 9 to Financial Statements for more details.
Interest expense and related charges decreased $2.064 billion, or 51%, to $1.946 billion in 2009. The decrease reflected a $696 million unrealized mark-to-market net gain related to interest rate swaps in 2009 compared to a $1.477 billion net loss in 2008, partially offset by $118 million in increased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges in August 2008.
Income tax expense totaled $407 million in 2009 compared to an income tax benefit totaling $450 million in 2008. Excluding the impacts of the goodwill impairment of $70 million in 2009 and $8.0 billion in 2008, the effective income tax rate was 36.7% in 2009 and 32.6% in 2008. (These nondeductible charges distort the comparison; therefore, they have been excluded for purposes of a more meaningful discussion.) The increase in the rate reflects the effect of interest accrued for uncertain tax positions, which increased the rate on income in 2009 and decreased the rate on a loss in 2008.
After-tax results for the segment improved $9.560 billion to net income of $631 million in 2009, reflecting the 2008 impairment of goodwill, the 2008 impairment charges reported in other deductions and the change in unrealized mark-to-market values of interest rate swaps reported in interest expense, partially offset by lower net gains from commodity hedging and trading activities driven by lower unrealized mark-to-market net gains.
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Regulated Delivery Segment
The following tables present financial operating results of the Regulated Delivery segment for the years ended December 31, 2009 and 2008. Comparative segment results for the years ended December 31, 2010 and 2009 are discussed above with consolidated results of equity in earnings of unconsolidated subsidiaries. Effective January 1, 2010, Oncor (and its majority owner, Oncor Holdings) was deconsolidated as a result of amended consolidation accounting standards related to variable interest entities (see Note 3 to Financial Statements).
Financial Results
| Year Ended December 31, | ||||||||
| 2009 | 2008 | |||||||
Operating revenues | $ | 2,690 | $ | 2,580 | ||||
Operating costs | (908 | ) | (828 | ) | ||||
Depreciation and amortization | (557 | ) | (492 | ) | ||||
Selling, general and administrative expenses | (194 | ) | (164 | ) | ||||
Franchise and revenue-based taxes | (250 | ) | (255 | ) | ||||
Impairment of goodwill | — | (860 | ) | |||||
Other income | 49 | 45 | ||||||
Other deductions | (34 | ) | (19 | ) | ||||
Interest income | 43 | 45 | ||||||
Interest expense and related charges | (346 | ) | (317 | ) | ||||
Income (loss) before income taxes | 493 | (265 | ) | |||||
Income tax expense (a) | (173 | ) | (221 | ) | ||||
Net income (loss) | $ | 320 | $ | (486 | ) | |||
| (a) | Effective with the sale of noncontrolling interests (see Note 14 to Financial Statements), Oncor is taxed as a partnership and thus not subject to income taxes; however, subsequent to the sale, Oncor reflects a “provision in lieu of income taxes,” and the results of segments are evaluated as if they file their own income tax returns. |
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Operating Data
| Year Ended December 31, | ||||||||
| 2009 | 2008 | |||||||
Operating statistics – volumes: | ||||||||
Electric energy billed volumes (GWh) | 103,376 | 107,828 | ||||||
Reliability statistics (a): | ||||||||
System Average Interruption Duration Index (SAIDI) (nonstorm) | 84.5 | 85.4 | ||||||
System Average Interruption Frequency Index (SAIFI) (nonstorm) | 1.1 | 1.1 | ||||||
Customer Average Interruption Duration Index (CAIDI) (nonstorm) | 77.2 | 74.7 | ||||||
Electric points of delivery (end of period and in thousands): | ||||||||
Electricity distribution points of delivery (based on number of meters) | 3,145 | 3,123 | ||||||
Operating revenues: | ||||||||
Electricity distribution revenues (b): | ||||||||
Affiliated (TCEH) | $ | 1,017 | $ | 998 | ||||
Nonaffiliated | 1,339 | 1,264 | ||||||
Total distribution revenues | 2,356 | 2,262 | ||||||
Third-party transmission revenues | 299 | 280 | ||||||
Other miscellaneous revenues | 35 | 38 | ||||||
Total operating revenues | $ | 2,690 | $ | 2,580 | ||||
| (a) | SAIDI is the average number of minutes electric service is interrupted per consumer in a year. SAIFI is the average number of electric service interruptions per consumer in a year. CAIDI is the average duration in minutes per electric service interruption in a year. The statistics presented are based on the preceding twelve months’ data. |
| (b) | Includes transition charge revenue associated with the issuance of securitization bonds totaling $147 million and $140 million for the years ended December 31, 2009 and 2008, respectively. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs. |
Regulated Delivery Segment — Financial Results — Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Operating revenues increased $110 million, or 4%, to $2.690 billion in 2009. The increase reflected:
| • | $55 million from increased distribution tariffs, including the August 2009 rate review order; |
| • | $28 million from a surcharge to recover advanced metering deployment costs and $11 million from a surcharge to recover additional energy efficiency costs, both of which became effective with the January 2009 billing cycle; |
| • | $20 million in higher transmission revenues reflecting rate increases to recover ongoing investment in the transmission system; |
| • | an estimated $14 million impact from growth in points of delivery; |
| • | $9 million performance bonus for meeting PUCT energy efficiency targets, and |
| • | $7 million in higher charges to REPs related to transition bonds (with an offsetting increase in amortization of the related regulatory asset), |
partially offset by an estimated $27 million in lower average consumption primarily due to the effects of milder weather and general economic conditions and $7 million due to less requested REP discretionary and third-party maintenance services.
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Operating costs increased $80 million, or 10%, to $908 million in 2009. The increase reflected $45 million in higher fees paid to other transmission entities, $21 million in additional expense recognition as a result of the PUCT’s August 2009 final order in the rate review (see discussion immediately below) and $10 million in costs related to programs designed to improve customer electricity demand efficiency, the majority of which are reflected in the revenue increases discussed above.
Under accounting rules for rate regulated utilities, certain costs are deferred as regulatory assets (see Note 24 to Financial Statements) when incurred and are recognized as expense when recovery of the costs are allowed in revenue under regulatory approvals. Accordingly, beginning in September 2009, the effective date of the new tariffs resulting from the rate review, Oncor began to amortize as operating costs or SG&A expenses certain costs previously deferred as regulatory assets over the recoverability period under the rate review order and recognized higher costs related to the current period. The additional expense recognized included $14 million related to storm recovery costs and $10 million related to pension and OPEB costs (including $3 million reported in SG&A expense).
Depreciation and amortization increased $65 million, or 13%, to $557 million in 2009. The increase reflected $34 million in higher depreciation due to ongoing investments in property, plant and equipment (including $11 million related to advanced meters), $24 million due to increased depreciation and amortization rates implemented upon the PUCT approval of new tariffs in September 2009 and $7 million in higher amortization of regulatory assets associated with securitization bonds (with an offsetting increase in revenues).
SG&A expenses increased $30 million, or 18%, to $194 million in 2009. The increase reflected $12 million related to advanced meters and $3 million in additional expense recognition as a result of the PUCT’s final order in the rate review, both of which have related revenue increases, $8 million in higher professional and contractor fees driven by outsourcing transition and CREZ development activities and $6 million in higher costs related to employee benefit plans, partially offset by a $3 million one-time reversal of bad debt expense due to the PUCT’s finalization of the Certification of Retail Electric Providers rule in April 2009. Write-offs of uncollectible amounts owed by nonaffiliated REPs are deferred as a regulatory asset.
Taxes other than amounts related to income taxes decreased $5 million, or 2%, to $250 million in 2009 reflecting a decrease in local franchise fees due to decreased volumes of electricity delivered.
See Note 4 to Financial Statements for a discussion of the $860 million goodwill impairment charge recorded in 2008.
Other income totaled $49 million in 2009 and $45 million in 2008. The 2009 and 2008 amounts included accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting totaling $39 million and $44 million, respectively. The 2009 amount also included $10 million due to the reversal of exit liabilities recorded in purchase accounting related to the termination of outsourcing arrangements. See Note 19 to Financial Statements.
Other deductions totaled $34 million in 2009 and $19 million in 2008. The 2009 amount included a $25 million write off of regulatory assets (see Note 24 to Financial Statements). The 2009 and 2008 amounts included costs totaling $2 million and $13 million, respectively, associated with a rate settlement with certain cities in 2006.
Interest income decreased $2 million, or 4%, to $43 million in 2009. The decrease reflected $4 million in lower reimbursement of transition bond interest from TCEH due to lower remaining principal amounts of the bonds and $2 million in lower interest income on temporary cash investments and restricted cash due to lower interest rates, partially offset by $4 million in higher earnings on investments held for certain employee benefit plans.
Interest expense and related charges increased $29 million, or 9%, to $346 million in 2009. The increase reflected $17 million in higher average borrowings, reflecting ongoing capital investments. The increase also reflected $12 million due to higher average interest rates, which was driven by refinancing of short-term borrowings with $1.5 billion of senior secured notes issued in September 2008. The majority of the proceeds of the September 2008 notes issuance was used to pay outstanding short-term borrowings under Oncor’s credit facility.
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Income tax expense totaled $173 million in 2009 compared to $221 million in 2008. The effective rate decreased to 35.1% in 2009 from 37.2% in 2008, excluding the impact of the $860 million goodwill impairment in 2008. (This nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The decrease in the rate was driven by the reversal of accrued interest due to the favorable resolution of uncertain tax positions.
Net income for 2009 totaled $320 million and net loss for 2008 totaled $486 million. The change reflects the $860 million goodwill impairment charge recorded in 2008, as well as $53 million in lower results in 2009 driven by the effect of lower average consumption on revenues, the write-off of certain regulatory assets and increased interest expense.
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Energy-Related Commodity Contracts and Mark-to-Market Activities
The table below summarizes the changes in commodity contract assets and liabilities for the periods presented. The net changes in these assets and liabilities, excluding “other activity” as described below, represent the pretax effect on earnings of positions in the commodity contract portfolio that are marked-to-market in net income (see Note 17 to Financial Statements). The portfolio consists primarily of economic hedges but also includes trading positions.
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Commodity contract net asset (liability) as of beginning of period | $ | 1,718 | $ | 430 | $ | (1,917 | ) | |||||
Settlements of positions (a) | (943 | ) | (518 | ) | 39 | |||||||
Changes in fair value (b) | 2,162 | 1,741 | 2,294 | |||||||||
Other activity (c) | 160 | 65 | 14 | |||||||||
Commodity contract net asset as of end of period | $ | 3,097 | $ | 1,718 | $ | 430 | ||||||
| (a) | Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and losses recognized in the settlement period). |
| (b) | Represents unrealized gains and losses recognized, primarily related to positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”). Includes gains and losses recorded at contract inception dates (see Note 17 to the Financial Statements). |
| (c) | The 2010 amount includes a $116 million noncash gain on termination of a long-term power sales contract. Includes amounts related to options purchased and sold and physical natural gas exchange transactions. |
Unrealized gains and losses related to commodity contracts are summarized as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Unrealized gains (losses) related to contracts marked-to-market | $ | 1,219 | $ | 1,223 | $ | 2,333 | ||||||
Ineffectiveness gains (losses) related to cash flow hedges | 2 | 2 | (4 | ) | ||||||||
Total unrealized gains (losses) related to commodity contracts | $ | 1,221 | $ | 1,225 | $ | 2,329 | ||||||
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Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of December 31, 2010, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
| Maturity dates of unrealized commodity contract asset as of December 31, 2010 | ||||||||||||||||||||
Source of fair value | Less than 1 year | 1-3 years | 4-5 years | Excess of 5 years | Total | |||||||||||||||
Prices actively quoted | $ | (139 | ) | $ | (9 | ) | $ | — | $ | — | $ | (148 | ) | |||||||
Prices provided by other external sources | 1,248 | 1,655 | — | — | 2,903 | |||||||||||||||
Prices based on models | (7 | ) | (21 | ) | 370 | — | 342 | |||||||||||||
Total | $ | 1,102 | $ | 1,625 | $ | 370 | $ | — | $ | 3,097 | ||||||||||
Percentage of total fair value | 36 | % | 52 | % | 12 | % | — | % | 100 | % | ||||||||||
The “prices actively quoted” category reflects only exchange traded contracts for which active quotes are readily available. The “prices provided by other external sources” category represents forward commodity positions valued using prices for which over-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT that are deemed active markets (excluding the West hub) generally extend through 2013 and over-the-counter quotes for natural gas generally extend through 2015, depending upon delivery point. The “prices based on models” category contains the value of all nonexchange traded options, valued using option pricing models. In addition, this category contains other contractual arrangements that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 15 to Financial Statements for fair value disclosures and discussion of fair value measurements.
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COMPREHENSIVE INCOME
Cash flow hedge activity reported in other comprehensive income included (all amounts after-tax):
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Net decrease in fair value of cash flow hedges: | ||||||||||||
Commodities | $ | — | $ | (20 | ) | $ | (8 | ) | ||||
Financing – interest rate swaps | — | — | (175 | ) | ||||||||
| — | (20 | ) | (183 | ) | ||||||||
Derivative value net losses reported in net income that relate to hedged transactions recognized in the period: | ||||||||||||
Commodities | 1 | 11 | 11 | |||||||||
Financing – interest rate swaps | 58 | 119 | 111 | |||||||||
| 59 | 130 | 122 | ||||||||||
Total income (loss) effect of cash flow hedges reported in other comprehensive income | $ | 59 | $ | 110 | $ | (61 | ) | |||||
We have historically used, and expect to continue to use, derivative instruments that are effective in offsetting future cash flow variability in interest rates and energy commodity prices, but as of December 31, 2010 and 2009, there were no such instruments accounted for as cash flow or fair value hedges. Amounts in accumulated other comprehensive income include the value of dedesignated and terminated cash flow hedges at the time of such dedesignation/termination, less amounts reclassified to earnings as the original hedged transactions are recognized, unless the hedged transactions become probable of not occurring. The effects of the hedge will be recorded in the statement of income as the hedged transactions are actually settled and affect earnings. Also see Note 17 to Financial Statements.
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FINANCIAL CONDITION
Liquidity and Capital Resources
Operating Cash Flows
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 — Cash provided by operating activities declined $605 million to $1.106 billion in 2010. The deconsolidation of Oncor in 2010 reduced reported cash provided by operating activities by $932 million. The decrease also reflected a $350 million effect of the amended accounting standard related to the accounts receivable securitization program (see Note 10 to Financial Statements), under which the $383 million of funding under the program upon the January 1, 2010 adoption is reported as a use of operating cash flows and a source of financing cash flows, with subsequent 2010 activity reported as financing, and the $33 million decline in funding in 2009 is reported as use of operating cash flows. These accounting effects were partially offset by improved working capital performance, particularly in retail accounts receivable due to the effects in 2009 of implementing a new customer information management system and more timely collections in 2010, as well as higher cash earnings from the competitive business driven by the contribution of the new generation units.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 —Cash provided by operating activities totaled $1.711 billion and $1.505 billion in 2009 and 2008, respectively. The $206 million increase reflected:
| • | a $489 million decrease in cash interest paid due to the payment of approximately $465 million of interest with an increase in toggle notes instead of cash as discussed under “Toggle Notes Interest Election” below, and |
| • | a $57 million favorable impact of timing of advanced metering surcharges, |
partially offset by a $347 million decrease in net margin deposits received primarily due to the effects of forward natural gas prices on positions in the long-term hedging program.
Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $371 million, $418 million and $460 million for the years ended December 31, 2010, 2009 and 2008, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent with industry practice, and amortization of intangible net assets and debt fair value discounts arising from purchase accounting that is reported in various other income statement line items including operating revenues, fuel and purchased power costs and delivery fees, other income and interest expense and related charges.
Financing Cash Flows
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 — Cash used in financing activities totaled $264 million in 2010 compared to cash provided of $422 million in 2009. The $686 million change was driven by debt repurchases under our liability management program (see Note 11 to Financial Statements), partially offset by the effect of the amended accounting standard related to the accounts receivable securitization program (see Note 10 to Financial Statements), under which the $96 million of funding under the program in 2010 is reported as financing cash flows.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 —Cash provided by financing activities totaled $422 million and $2.837 billion in 2009 and 2008, respectively. The $2.415 billion decrease was driven by $1.253 billion in net proceeds from the sale of noncontrolling interests in 2008 (see Note 14 to Financial Statements) and reduced borrowings in 2009 related to the construction of new generation facilities, which were nearing completion.
See Note 11 to Financial Statements for further detail of short-term borrowings and long-term debt.
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Investing Cash Flows
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 — Cash used in investing activities totaled $468 million and $2.633 billion in 2010 and 2009, respectively. Capital expenditures (excluding nuclear fuel) totaled $838 million and $2.348 billion in 2010 and 2009, respectively. The $1.510 billion decline in capital spending reflected the deconsolidation of Oncor ($998 million capital expenditures in 2009) (see Note 3 to Financial Statements) in 2010 and a decrease in spending related to the construction of the now complete new generation facilities. The decline in cash used in investing activities also reflected a $400 million cash investment posted with a derivative counterparty in 2009 that was returned in 2010.
Capital expenditures in 2010 consisted of:
| • | $487 million for major maintenance, primarily in existing generation operations; |
| • | $140 million related to completion of the construction of a second generation unit and mine development at Oak Grove; |
| • | $106 million for environmental expenditures related to existing generation units; |
| • | $42 million for information technology and other corporate investments; |
| • | $34 million related to nuclear generation development, and |
| • | $29 million primarily related to the new retail customer information system. |
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 —Cash used in investing activities totaled $2.633 billion and $2.934 billion in 2009 and 2008, respectively, including capital expenditures totaling $2.348 billion and $2.849 billion, respectively. The decline in capital spending primarily reflected a decrease in spending related to the construction of the new generation facilities, partially offset by capital expenditures in the regulated business for advanced metering deployment and CREZ.
Debt Financing Activity—Activities related to short-term borrowings and long-term debt during the year ended December 31, 2010 are as follows (all amounts presented are principal, and repayments and repurchases include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):
| Borrowings (a) | Repayments and Repurchases (b) | |||||||
TCEH | $ | 1,779 | $ | 2,758 | ||||
EFCH | — | 9 | ||||||
EFIH | 2,180 | — | ||||||
EFH Corp. | 1,255 | 4,444 | ||||||
Total long-term | 5,214 | 7,211 | ||||||
Total short-term – TCEH (c) | 172 | — | ||||||
Total | $ | 5,386 | $ | 7,211 | ||||
| ||||||||
| (a) | Includes the following activities (see Note 11 to Financial Statements): |
| • | $500 million of EFH Corp. 10% Notes issued by EFH Corp., the proceeds of which may be used in debt exchanges or repurchases. |
| • | $350 million of TCEH 15% Notes issued by TCEH, the net proceeds from which were used to repurchase TCEH Senior Notes. |
| • | Principal increases in payment of accrued interest totaling $194 million and $205 million of EFH Corp. and TCEH Toggle Notes, respectively. |
| • | $561 million of EFH Corp. 10% Notes issued by EFH Corp. in debt exchanges. |
| • | $2.180 billion of EFIH 10% Notes issued by EFIH in debt exchanges. |
| • | $1.221 billion of TCEH 15% Notes issued by TCEH in debt exchanges. |
| (b) | Includes $5.862 billion of noncash retirements (including discounts captured on cash repurchases) as a result of 2010 debt exchange and repurchase transactions discussed in Note 11 to Financial Statements. |
| (c) | Short-term amounts represent net borrowings/repayments. |
See Note 11 to Financial Statements for further detail of long-term debt and other financing arrangements.
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We regularly monitor the capital and bank credit markets for liability management opportunities that we believe will improve our balance sheet, including capturing debt discount and extending debt maturities. As a result, we may engage, from time to time, in liability management transactions. Future activities under the liability management program may include the purchase of our outstanding debt for cash in open market purchases or privately negotiated transactions (including pursuant to a Section 10b-5(1) plan) or via public or private exchange or tender offers. Moreover, as part of our liability management program, we may refinance our existing debt, including the TCEH Senior Secured Credit Facilities.
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.
Available Liquidity — The following table summarizes changes in available liquidity for the year ended December 31, 2010 (excluding Oncor):
| Available Liquidity | ||||||||||||
| December 31, 2010 | December 31, 2009 | Change | ||||||||||
Cash and cash equivalents | $ | 1,534 | $ | 1,161 | $ | 373 | ||||||
TCEH Revolving Credit Facility (a) | 1,440 | 1,721 | (281 | ) | ||||||||
TCEH Letter of Credit Facility | 261 | 399 | (138 | ) | ||||||||
Subtotal | $ | 3,235 | $ | 3,281 | $ | (46 | ) | |||||
Short-term investment (b) | — | 490 | (490 | ) | ||||||||
Total liquidity (c) | $ | 3,235 | $ | 3,771 | $ | (536 | ) | |||||
| (a) | As of December 31, 2010 and 2009, the TCEH Revolving Credit Facility includes $94 million and $141 million, respectively, of commitments from Lehman that are only available from the fronting banks and the swingline lender. |
| (b) | December 31, 2009 amount includes $425 million cash investment (including accrued interest) and $65 million in letters of credit posted related to certain interest rate and commodity hedge transactions. Pursuant to the related agreement, the collateral was returned in March 2010. See Note 17 to Financial Statements. |
| (c) | As of December 31, 2010 and 2009, total liquidity includes $465 million and $333 million, respectively, of net receipts of margin deposits from counterparties related to commodity positions (net of $166 million and $187 million, respectively, posted with counterparties). |
Note: Available liquidity in the future could benefit from additional exercises of the payment-in-kind (PIK) option on the EFH Corp. Toggle Notes and TCEH Toggle Notes, which for the remaining payment dates from May 2011 through November 2012 would avoid cash interest payments of approximately $424 million.
See Note 11 to Financial Statements for additional discussion of the credit facilities.
The $536 million decrease in available liquidity reflected the impact of the liability management program and an increase in letters of credit posted as collateral support with ERCOT in conjunction with ERCOT’s transition to a nodal wholesale market structure.
Pension and OPEB Plan Funding— Pension and OPEB plan funding is expected to total $175 million and $26 million, respectively, in 2011. Based on the funded status of the pension plan as of December 31, 2010, funding is expected to total $932 million for the 2011 to 2015 period. The increase in funding reflects requirements under the Pension Protection Act of 2006, which were impacted by the effect of lower interest rates in the computation of our pension liability. Oncor is expected to fund 72% of this amount consistent with its share of the pension liability. We made pension and OPEB contributions of $45 million and $25 million, respectively, in 2010, of which $58 million was contributed by Oncor.
See Note 20 to Financial Statements for more information regarding the pension and OPEB plans, including the funded status of the plans as of December 31, 2010.
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Toggle Notes Interest Election — EFH Corp. and TCEH have the option every six months at their discretion, ending with the interest payment due November 2012, to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments. We elected to do so beginning with the May 2009 interest payment as an efficient and cost-effective method to further enhance liquidity. Once EFH Corp. and/or TCEH make a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. and/or TCEH revoke the applicable election. Use of the PIK feature will be evaluated at each election period, taking into account market conditions and other relevant factors at such time.
EFH Corp. made its 2010 and 2009 interest payments and will make its May 2011 interest payment on the EFH Corp. Toggle Notes by using the PIK feature of those notes. During such applicable interest periods, the interest rate on these notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the notes by $194 million in 2010 (excluding $130 million principal amount issued to EFIH as holder of $2.166 billion principal amount of EFH Corp. Toggle Notes acquired in the debt exchange completed in August 2010 that is eliminated in consolidation) and $309 million in 2009 and is expected to further increase the aggregate principal amount of the notes by $34 million in May 2011 (excluding $138 million principal amount expected to be issued to EFIH). The elections increased liquidity in 2010 by an amount equal to $182 million (excluding $122 million related to notes held by EFIH) and is expected to further increase liquidity in May 2011 by an amount equal to a currently estimated $32 million (excluding $129 million related to notes held by EFIH), constituting the amounts of cash interest that otherwise would have been payable on the notes.
Similarly, TCEH made its 2010 and 2009 interest payments and will make its May 2011 interest payment on the TCEH Toggle Notes by using the PIK feature of those notes. During the applicable interest periods, the interest rate on the notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the notes by approximately $212 million in 2010, including $7 million principal amount paid to EFH Corp. and eliminated in consolidation, and $202.5 million in 2009 and is expected to further increase the aggregate principal amount of the notes by $79 million in May 2011. The elections increased liquidity in 2010 by an amount equal to $198 million and is expected to further increase liquidity in May 2011 by an amount equal to an estimated $74 million, constituting the amounts of cash interest that otherwise would have been payable on the notes.
Liquidity Effects of Commodity Hedging and Trading Activities — Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other forms of credit support to satisfy such collateral obligations. In addition, TCEH’s Commodity Collateral Posting Facility (CCP facility), an uncapped senior secured revolving credit facility that matures in December 2012, funds the cash collateral posting requirements for a significant portion of the positions in the long-term hedging program not otherwise secured by a first-lien in the assets of TCEH. The aggregate principal amount of the CCP facility is determined by the exposure arising from higher forward market prices, regardless of the amount of such exposure, on a portfolio of certain natural gas hedging transaction volumes. Including those hedging transactions where margin deposits are covered by unlimited borrowings under the CCP facility, as of December 31, 2010, more than 95% of the long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral requirements for those hedging transactions. Due to declines in forward natural gas prices, no amounts were borrowed against the CCP facility at December 31, 2010 and 2009. See Note 11 to Financial Statements for more information about the TCEH Senior Secured Facilities, which includes the CCP facility.
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As of December 31, 2010, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:
| • | $165 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $183 million posted as of December 31, 2009; |
| • | $630 million in cash has been received from counterparties, net of $1 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $516 million received, net of $4 million in cash posted, as of December 31, 2009; |
| • | $473 million in letters of credit have been posted with counterparties, as compared to $379 million posted as of December 31, 2009, and |
| • | $25 million in letters of credit have been received from counterparties, as compared to $44 million received as of December 31, 2009. |
With respect to exchange cleared transactions, these transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variance margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. With respect to cash collateral that is received, such cash collateral is either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or it is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing liquidity in the event that it was not restricted. As of December 31, 2010, restricted cash collateral held totaled $33 million. See Note 24 to Financial Statements regarding restricted cash.
With the long-term hedging program, increases in natural gas prices generally result in increased cash collateral and letter of credit postings to counterparties. As of December 31, 2010, approximately 300 million MMBtu of positions related to the long-term hedging program were not directly secured on an asset-lien basis and thus have cash collateral posting requirements. The uncapped CCP facility supports the collateral posting requirements related to most of these transactions.
Interest Rate Swap Transactions —See Note 11 to Financial Statements for TCEH interest rate swaps entered into as of December 31, 2010.
Income Tax Refunds/Payments —Income tax payments related to the Texas margin tax are expected to total approximately $65 million, and net refunds of federal income taxes are expected to total approximately $57 million in the next 12 months. Payments in the year ended December 31, 2010 totaled $64 million. In 2009, we received a refund totaling $98 million in income taxes and related interest related to IRS audits of 1993 and 1994 income tax returns and made net payments totaling approximately $44 million related to the Texas margin tax. In 2008, we received net federal income tax refunds of $229 million, including $98 million related to 2007 tax payments and $142 million related to a net operating loss carryback to the 2006 tax year.
As discussed in Note 7 to Financial Statements, we assess uncertain tax positions under a “more-likely-than-not” standard. We cannot reasonably estimate the ultimate amounts and timing of tax payments associated with uncertain tax positions, but expect that no material federal income tax payments related to such positions will be made in 2011.
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Accounts Receivable Securitization Program — TXU Energy participates in EFH Corp.’s accounts receivable securitization program with financial institutions (the funding entities). As discussed in Note 1 to Financial Statements, in accordance with amended transfers and servicing accounting standards, the trade accounts receivable amounts under the program are reported as pledged balances and the related funding amounts are reported as short-term borrowings. Under the program, TXU Energy (originator) sells retail trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp., which sells undivided interests in the purchased accounts receivable for cash to entities established for this purpose by the funding entities. All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $96 million and $383 million as of December 31, 2010 and 2009, respectively. See Note 10 to Financial Statements for a more complete description of the program including amendments to the program in June 2010 and a related reduction in funding, the impact of the program on the financial statements for the periods presented and the contingencies that could result in termination of the program and a reduction of liquidity should the underlying financing be settled.
Liquidity Needs, Including Capital Expenditures —Capital expenditures, including capitalized interest, for 2011 are expected to total approximately $700 million and include:
| • | $525 million for investments in TCEH generation facilities, including approximately: |
| • | $450 million for major maintenance, primarily in generation operations, and |
| • | $75 million for environmental expenditures related to generation units (a); |
| • | $125 million for nuclear fuel purchases, and |
| • | $50 million for information technology and other corporate investments. |
| (a) | Expenditures are classified as environmental in nature if the projects are the direct result of environmental regulations. |
We expect cash flows from operations combined with availability under our credit facilities discussed in Note 11 to Financial Statements to provide sufficient liquidity to fund our current obligations, projected working capital requirements and capital spending for a period that includes the next twelve months.
Distributions from Oncor —Until December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor’s net income determined in accordance with GAAP, subject to certain defined adjustments. Distributions are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. (See Note 13 to Financial Statements.) Also, see “Regulatory Matters — Oncor Matters with the PUCT” for discussion of a rate review filed by Oncor in January 2011 that, among other things, requests a revised regulatory capital structure of 55% debt to 45% equity.
In January 2009, the PUCT awarded certain CREZ construction projects to Oncor. See discussion below under “Regulatory Matters – Oncor Matters with the PUCT.” As a result of the increased capital expenditures for CREZ and the debt-to-equity ratio cap, we expect distributions to EFH Corp. from Oncor will be substantially reduced or temporarily discontinued during the CREZ construction period, which is expected to be completed in 2013.
Capitalization — Our capitalization ratios consisted of 120.9% and 104.6% long-term debt, less amounts due currently, and (20.9)% and (4.6)% common stock equity, as of December 31, 2010 and 2009, respectively. Total debt to capitalization, including short-term debt, was 119.6% and 104.4% as of December 31, 2010 and 2009, respectively.
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Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain of our financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of December 31, 2010, we were in compliance with all such maintenance covenants.
Covenants and Restrictions under Financing Arrangements—Each of the TCEH Senior Secured Facilities and the indentures governing substantially all of the debt we have issued in connection with, and subsequent to, the Merger contain covenants that could have a material impact on the liquidity and operations of EFH Corp. and its subsidiaries.
Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. Senior Secured Notes) for the year ended December 31, 2010 totaled $5.240 billion for EFH Corp. See Exhibits 99(b), 99(c) and 99(d) for a reconciliation of net income to Adjusted EBITDA for EFH Corp., TCEH and EFIH, respectively, for the years ended December 31, 2010 and 2009.
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The table below summarizes TCEH’s secured debt to Adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp., EFIH and TCEH that are applicable under certain other threshold covenants in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the TCEH Senior Secured Second Lien Notes (for 2010), the EFH Corp. Senior Notes, the EFH Corp. Senior Secured Notes and the EFIH Notes as of December 31, 2010 and 2009. The debt incurrence and restricted payments/limitations on investments covenants thresholds described below represent levels that must be met in order for EFH Corp., EFIH or TCEH to incur certain permitted debt or make certain restricted payments and/or investments. EFH Corp. and its consolidated subsidiaries are in compliance with their maintenance covenants.
| December 31, 2010 | December 31, 2009 | Threshold Level as of December 31, 2010 | ||||||||||
Maintenance Covenant: | ||||||||||||
TCEH Senior Secured Facilities: | ||||||||||||
Secured debt to Adjusted EBITDA ratio (a) | 5.19 to 1.00 | 4.76 to 1.00 | Must not exceed 6.75 to 1.00 (b) | |||||||||
Debt Incurrence Covenants: | ||||||||||||
EFH Corp. Senior Secured Notes: | ||||||||||||
EFH Corp. fixed charge coverage ratio | 1.3 to 1.0 | 1.2 to 1.0 | At least 2.0 to 1.0 | |||||||||
TCEH fixed charge coverage ratio | 1.5 to 1.0 | 1.5 to 1.0 | At least 2.0 to 1.0 | |||||||||
EFIH Notes: | ||||||||||||
EFIH fixed charge coverage ratio (c) | (d) | 53.8 to 1.0 | At least 2.0 to 1.0 | |||||||||
TCEH Senior Notes and TCEH Senior Secured Second Lien Notes: | ||||||||||||
TCEH fixed charge coverage ratio | 1.5 to 1.0 | 1.5 to 1.0 | At least 2.0 to 1.0 | |||||||||
TCEH Senior Secured Facilities: | ||||||||||||
TCEH fixed charge coverage ratio | 1.5 to 1.0 | 1.5 to 1.0 | At least 2.0 to 1.0 | |||||||||
Restricted Payments/Limitations on Investments Covenants: | ||||||||||||
EFH Corp. Senior Notes: | ||||||||||||
General restrictions (Sponsor Group payments): | ||||||||||||
EFH Corp. leverage ratio | 8.5 to 1.0 | 9.4 to 1.0 | Equal to or less than 7.0 to 1.0 | |||||||||
EFH Corp. Senior Secured Notes: | ||||||||||||
General restrictions (non-Sponsor Group payments): | ||||||||||||
EFH Corp. fixed charge coverage ratio (e) | 1.6 to 1.0 | 1.4 to 1.0 | At least 2.0 to 1.0 | |||||||||
General restrictions (Sponsor Group payments): | ||||||||||||
EFH Corp. fixed charge coverage ratio (e) | 1.3 to 1.0 | 1.2 to 1.0 | At least 2.0 to 1.0 | |||||||||
EFH Corp. leverage ratio | 8.5 to 1.0 | 9.4 to 1.0 | Equal to or less than 7.0 to 1.0 | |||||||||
EFIH Notes: | ||||||||||||
General restrictions (non-EFH Corp. payments): | ||||||||||||
EFIH fixed charge coverage ratio (c) (f) | 23.9 to 1.0 | 3.9 to 1.0 | At least 2.0 to 1.0 | |||||||||
General restrictions (EFH Corp. payments): | ||||||||||||
EFIH fixed charge coverage ratio (c) (f) | (d) | 53.8 to 1.0 | At least 2.0 to 1.0 | |||||||||
EFIH leverage ratio | 5.3 to 1.0 | 4.4 to 1.0 | Equal to or less than 6.0 to 1.0 | |||||||||
TCEH Senior Notes and TCEH Senior Secured Second Lien Notes: | ||||||||||||
TCEH fixed charge coverage ratio | 1.5 to 1.0 | 1.5 to 1.0 | At least 2.0 to 1.0 | |||||||||
TCEH Senior Secured Facilities: | ||||||||||||
Payments to Sponsor Group: | ||||||||||||
TCEH total debt to Adjusted EBITDA ratio | 7.9 to 1.0 | 8.4 to 1.0 | Equal to or less than 6.5 to 1.0 | |||||||||
| (a) | In accordance with the terms of the TCEH Senior Secured Facilities and as the result of the new Sandow and first Oak Grove generating units achieving average capacity factors of greater than or equal to 70% for the three months ended March 31, 2010, the maintenance covenant as of December 31, 2010 includes Adjusted EBITDA for the units and the proportional amount of outstanding debt under the Delayed Draw Term Loan (see Note 11 to Financial Statements) applicable to the two units. |
| (b) | Threshold level will decrease to a maximum of 6.50 to 1.00 effective December 31, 2011. Calculation excludes secured debt that ranks junior to the TCEH Senior Secured Facilities. |
| (c) | Although EFIH currently meets the fixed charge coverage ratio threshold applicable to certain covenants contained in the indentures governing the EFIH Notes, EFIH’s ability to use such thresholds to incur debt or make restricted payments/investments is currently limited by the covenants contained in the EFH Corp. Senior Notes and the EFH Corp. Senior Secured Notes. |
| (d) | EFIH meets the ratio threshold. Because EFIH’s interest income exceeds interest expense, the result of the ratio calculation is not meaningful. |
| (e) | The EFH Corp. fixed charge coverage ratio for non-Sponsor Group payments includes the results of Oncor Holdings and its subsidiaries. The EFH Corp. fixed charge coverage ratio for Sponsor Group payments excludes the results of Oncor Holdings and its subsidiaries. |
| (f) | The EFIH fixed charge coverage ratio for non-EFH Corp. payments includes the results of Oncor Holdings and its subsidiaries. The EFIH fixed charge coverage ratio for EFH Corp. payments excludes the results of Oncor Holdings and its subsidiaries. |
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Material Credit Rating Covenants and Credit Worthiness Effects on Liquidity — As a result of TCEH’s non-investment grade credit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, as of December 31, 2010, counterparties to those contracts could have required TCEH to post up to an aggregate of $17 million in additional collateral. This amount largely represents the below market terms of these contracts as of December 31, 2010; thus, this amount will vary depending on the value of these contracts on any given day.
Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. As of December 31, 2010, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $28 million, with $14 million of this amount posted for the benefit of Oncor.
The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of December 31, 2010, TCEH posted letters of credit in the amount of $73 million, which are subject to adjustments.
The RRC has rules in place to assure adequate credit worthiness of parties that have mining reclamation obligations. Under these rules, should the RRC determine that the credit worthiness of Luminant Generation Company LLC (a subsidiary of TCEH) is not sufficient to support its reclamation obligations, TCEH may be required to post cash or letter of credit collateral support in an amount currently estimated to be approximately $650 million to $900 million. The actual amount (if required) could vary depending upon numerous factors, including Luminant Generation Company LLC’s credit worthiness and the level of mining reclamation obligations.
ERCOT has rules in place to assure adequate credit worthiness of parties that participate in the “day-ahead” and “real-time markets” operated by ERCOT. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $240 million as of December 31, 2010 (which is subject to weekly adjustments based on settlement activity with ERCOT). This amount includes an increase of approximately $200 million in letters of credit in the fourth quarter 2010 driven by the December 2010 implementation of the nodal wholesale market.
Other arrangements of EFH Corp. and its subsidiaries, including Oncor’s credit facility, the accounts receivable securitization program (see Note 10 to Financial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the relevant credit ratings.
In the event that any or all of the additional collateral requirements discussed above are triggered, we believe we will have adequate liquidity to satisfy such requirements.
Material Cross Default Provisions — Certain financing arrangements contain provisions that may result in an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenants that could or does result in an acceleration of payments due. Such provisions are referred to as “cross default” provisions.
A default by TCEH or any of its restricted subsidiaries in respect of indebtedness, excluding indebtedness relating to the accounts receivable securitization program, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity of outstanding balances ($22.304 billion as of December 31, 2010) under such facilities.
The indentures governing the TCEH Senior Notes and the TCEH Senior Secured Second Lien Notes contain a cross acceleration provision where a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of TCEH or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the TCEH Senior Notes and TCEH Senior Secured Second Lien Notes.
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Under the terms of a TCEH rail car lease, which had $45 million in remaining lease payments as of December 31, 2010 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.
Under the terms of another TCEH rail car lease, which had $50 million in remaining lease payments as of December 31, 2010 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.
The indentures governing the EFH Corp. Senior Secured Notes contain a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of EFH Corp. or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the EFH Corp. Senior Secured Notes.
The indentures governing the EFIH Notes contain a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of EFIH or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the EFIH Notes.
The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that applies in the aggregate to the originator, any parent guarantor of an originator or any subsidiary acting as collection agent under the program. TXU Receivables Company and EFH Corporate Services Company (a direct subsidiary of EFH Corp.), as collection agent, in the aggregate have a cross default threshold of $50,000. If any of the aforementioned defaults on indebtedness of the applicable threshold were to occur, the program could terminate.
We enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which vary, stated in the contracts. The subsidiaries whose default would trigger cross default vary depending on the contract.
Each of TCEH’s natural gas hedging agreements and interest rate swap agreements that are secured with a lien on its assets on a pari passu basis with the TCEH Senior Secured Facilities contains a cross default provision. In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but ranging from $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedging agreements would have the right to terminate its hedge or interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.
Other arrangements, including leases, have cross default provisions, the triggering of which would not be expected to result in a significant effect on liquidity.
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Long-Term Contractual Obligations and Commitments— The following table summarizes our contractual cash obligations as of December 31, 2010 (see Notes 11 and 12 to Financial Statements for additional disclosures regarding these long-term debt and noncancellable purchase obligations).
Contractual Cash Obligations | Less Than One Year | One to Three Years | Three to Five Years | More Than Five Years | Total | |||||||||||||||
Long-term debt – principal (a) | $ | 651 | $ | 533 | $ | 24,233 | $ | 10,003 | $ | 35,420 | ||||||||||
Long-term debt – interest (b) | 2,749 | 5,378 | 3,519 | 5,517 | 17,163 | |||||||||||||||
Operating and capital leases (c) | 69 | 124 | 96 | 275 | 564 | |||||||||||||||
Obligations under commodity purchase and services agreements (d) | 1,357 | 1,347 | 719 | 1,023 | 4,446 | |||||||||||||||
Total contractual cash obligations | $ | 4,826 | $ | 7,382 | $ | 28,567 | $ | 16,818 | $ | 57,593 | ||||||||||
| (a) | Excludes capital lease obligations, unamortized discounts and fair value premiums and discounts related to purchase accounting. Also excludes $113 million of additional principal amount of notes expected to be issued in May 2011 and due in 2016 and 2017, reflecting the election of the PIK feature on toggle notes as discussed above under “Toggle Notes Interest Election.” |
| (b) | Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interest rate swaps are calculated based on interest rates in effect as of December 31, 2010. |
| (c) | Includes short-term noncancellable leases. |
| (d) | Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments. Amounts presented for variable priced contracts assumed the year-end 2010 price remained in effect for all periods except where contractual price adjustment or index-based prices were specified. |
The following are not included in the table above:
| • | contracts between affiliated entities and intercompany debt; |
| • | individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts with one counterparty that are more than $1 million on an aggregated basis have been included); |
| • | contracts that are cancellable without payment of a substantial cancellation penalty; |
| • | employment contracts with management; |
| • | estimated funding of pension plan totaling $175 million in 2011 and approximately $932 million for the 2011 to 2015 period as discussed above under “Pension and OPEB Plan Funding,” and |
| • | liabilities related to uncertain tax positions totaling $1.6 billion discussed in Note 7 to Financial Statements as the ultimate timing of payment is not known. |
Guarantees — See Note 12 to Financial Statements for details of guarantees.
OFF–BALANCE SHEET ARRANGEMENTS
See Notes 3 and 12 to Financial Statements regarding VIEs and guarantees.
COMMITMENTS AND CONTINGENCIES
See Note 12 to Financial Statements for discussion of commitments and contingencies.
CHANGES IN ACCOUNTING STANDARDS
See Note 1 to Financial Statements for a discussion of changes in accounting standards.
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REGULATORY MATTERS
See discussions in Part I under “Environmental Regulations and Related Considerations” and in Note 12 to Financial Statements.
Sunset Review
PURA, the PUCT, the RRC, ERCOT, the TCEQ and the Office of Public Utility Counsel (OPUC) will be subject to “sunset” review by the Texas Legislature in the 2011 legislative session. Sunset review includes, generally, a comprehensive review of the need for and effectiveness of an administrative agency (the PUCT, the RRC, ERCOT, the TCEQ or the OPUC), along with an evaluation of the advisability of any changes to that agency’s authorizing legislation (PURA). In 2010, the Texas Sunset Advisory Commission adopted various recommendations regarding these agencies and submitted its recommendations for the Texas Legislature’s consideration early in the session, which began in January 2011. We cannot predict the outcome of the sunset review process.
Oncor Matters with the PUCT
Stipulation Approved by the PUCT—In April 2008, the PUCT entered an order (PUCT Docket No. 34077), which became final in June 2008, approving the terms of a stipulation relating to the filing in 2007 by Oncor and Texas Holdings with the PUCT pursuant to Section 14.101(b) of PURA and PUCT Substantive Rule 25.75. The filing reported an ownership change involving Texas Holdings’ purchase of EFH Corp. Among other things, the stipulation required the filing of a rate case by Oncor no later than July 1, 2008 based on a test year ended December 31, 2007, which Oncor filed in June 2008 as discussed below. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200th District Court of Travis County, Texas. A hearing on the appeal was held in June 2010, and the District Court affirmed the PUCT order in its entirety. Nucor Steel appealed that ruling to the Third District Court of Appeals in Austin, Texas in July 2010. Oral argument before the court is scheduled for March 2011. While Oncor is unable to predict the outcome of the appeal, it does not expect the appeal to affect the major provisions of the stipulation.
Rate Cases — 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. If approved as requested, this review would result in an aggregate annual rate increase of approximately $353 million over the test year period adjusted for the impact of weather. Oncor also requested a revised regulatory capital structure of 55% debt to 45% equity. The debt-to-equity ratio established by the PUCT is currently set at 60% debt to 40% equity. The PUCT, cities and other participating parties, with input from Oncor, established a procedural schedule for the review. A hearing on the merits of Oncor’s request is scheduled to commence in May 2011, and resolution of the proposed increase is expected to occur during the second half of 2011. Oncor cannot predict the outcome of this rate review.
In June 2008, Oncor filed for a rate review with the PUCT and 204 cities (PUCT Docket No. 35717). In August 2009, the PUCT issued a final order with respect to the rate review. The final order approved a total annual revenue requirement for Oncor of $2.64 billion, based on a 2007 test year cost of service and customer characteristics. New rates were calculated for all customer classes using 2007 test year billing metrics and the approved class cost allocation and rate design. The PUCT staff estimated that the final order resulted in an approximate $115 million increase in base rate revenues over Oncor’s 2007 adjusted test year revenues, before recovery of rate case expenses. Prior to implementing the new rates in September 2009, Oncor had already begun recovering $45 million of the $115 million increase as a result of approved transmission cost recovery factor and energy efficiency cost recovery factor filings, such as those discussed below.
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Key findings by the PUCT in the rate review included:
| • | recognizing and affirming Oncor’s corporate ring-fence from EFH Corp. and its unregulated affiliates by rejecting a proposed consolidated tax savings adjustment arising out of EFH Corp.’s ability to offset Oncor’s taxable income against losses from other investments; |
| • | approving the recovery of all of Oncor’s capital investment in its transmission and distribution system, including investment in certain automated meters that will be replaced pursuant to Oncor’s advanced meter deployment plan; |
| • | denying recovery of $25 million of regulatory assets, which resulted in a $16 million after-tax loss being recognized in the third quarter 2009, and |
| • | setting Oncor’s return on equity at 10.25%. |
New rates were implemented upon approval of new tariffs in September 2009. In November 2009, the PUCT issued an Order on Rehearing that established a new rate class but did not change the revenue requirements. In January 2010, the PUCT denied all Second Motions for Rehearing, which made the November 2009 Order on Rehearing final and appealable. Oncor and four other parties appealed various portions of the rate case final order to a state district court. Oral arguments in the appeal were held in October 2010. In January 2011, the District Court signed its judgment reversing the PUCT with respect to two issues: the PUCT’s disallowance of certain franchise fees and the PUCT’s decision that PURA no longer requires imposition of a rate discount for state colleges and universities. Oncor intends to file an appeal with the Austin Court of Appeals in February 2011 with respect to the issues it appealed to the District Court and did not prevail upon, as well as the District Court’s decision on discounts for state colleges and universities.
Competitive Renewable Energy Zones (CREZs) — In January 2009, the PUCT awarded Oncor 17 CREZ construction projects (PUCT Docket Nos. 35665 and 37902) requiring 14 related Certificate of Convenience and Necessity (CCN) amendment proceedings before the PUCT. As of February 2011, 16 of the 17 projects and 13 of the 14 CCN amendments have been approved by the PUCT. 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. Based on the selection of final routes for the three default and nine priority projects, identification of additional costs not included in the original ERCOT estimate (e.g., wind interconnection facilities and required modifications to existing facilities) and Oncor’s preferred routes for the remaining five subsequent projects, Oncor currently estimates that the cost of these projects will total approximately $1.75 billion. Individual project costs could change based on final route specifications for the subsequent projects as determined by the PUCT. In addition, ERCOT completed a study in December 2010 that will allow Oncor and other transmission service providers to build additional facilities to provide further voltage support to the transmission grid as a result of CREZ. Oncor and other transmission service providers are working with ERCOT to complete cost estimates for the required work by the second half of 2011. As of December 31, 2010, Oncor’s cumulative CREZ-related capital expenditures totaled $316 million, including $202 million during the year ended December 31, 2010. It is expected that the necessary permitting actions and other requirements and all construction activities for Oncor’s CREZ construction projects will be completed by the end of 2013.
Advanced Metering Deployment Surcharge Filing (PUCT Docket Nos. 35718 and 36157)— In May 2008, Oncor filed with the PUCT a description and request for approval of its proposed advanced metering system deployment plan and proposed surcharge for the recovery of estimated future investment for advanced metering deployment. In September 2008, a PUCT order became final approving a settlement reached with the majority of the parties to this surcharge filing. The settlement included the following major provisions, as amended by the final order in the 2008 rate review:
| • | the full deployment of over three million advanced meters to all residential and most non-residential retail electricity customers in Oncor’s service area; |
| • | a surcharge beginning on January 1, 2009 and continuing for 11 years; |
| • | a total revenue requirement over the surcharge period of $1.023 billion; |
| • | estimated capital expenditures for advanced metering facilities of $686 million; |
| • | related operation and maintenance expenses for the surcharge period of $153 million; |
| • | $204 million of operation and maintenance expense savings, and |
| • | an advanced metering cost recovery factor of $2.19 per month per residential retail customer and varying from $2.39 to $5.15 per month for non-residential retail customers. |
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As of December 31, 2010, Oncor has installed approximately 1,514,000 advanced digital meters, including approximately 854,000 during the year ended December 31, 2010. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $360 million as of December 31, 2010, including $164 million in 2010. Oncor expects to complete installations of the advanced meters by the end of 2012.
Oncor may, through subsequent reconciliation proceedings, request recovery of additional costs that are reasonable and necessary. While there is a presumption that costs spent in accordance with a plan approved by the PUCT are reasonable and necessary, recovery of any costs that are found not to have been spent or properly allocated, or not to be reasonable or necessary, must be refunded.
Transmission Cost Recovery and Rates (PUCT Docket Nos. 37882, 38460, 38938 and 38495)— In order to recover increases in its transmission costs, including incremental fees paid to other transmission service providers due to an increase in their rates, Oncor is allowed to request an update twice a year to the transmission cost recovery factor (TCRF) component of its retail delivery rates charged to REPs. In January 2010, an application was filed to increase the TCRF, which was administratively approved in February 2010 and became effective March 1, 2010. This application increased Oncor’s annualized revenues by approximately $13 million. In July 2010, an application was filed to increase the TCRF, which was administratively approved in August 2010 and became effective September 1, 2010. This application increased Oncor’s annualized revenues by approximately $15 million. In December 2010, an application was filed to increase the TCRF, which was administratively approved in January 2011 for implementation effective March 1, 2011. This application is expected to increase Oncor’s annualized revenues by approximately $33 million.
In July 2010, Oncor filed an application for an interim update of its wholesale transmission rate, and the PUCT approved the new rate effective September 29, 2010. Oncor’s annualized revenues increased by an estimated $43 million with $27 million of this increase recoverable through transmission rates charged to wholesale customers and the remaining $16 million recoverable from REPs through the TCRF component of Oncor’s delivery rates.
PUCT Rulemaking— In 2010, the PUCT published rule changes in two proceedings that impact transmission rates. In the first proceeding (PUCT Project No. 37909), the PUCT changed the TCRF rule to allow for more complete cost recovery of wholesale transmission charges incurred by distribution service providers. Previously, increased wholesale transmission charges were recoverable by distribution service providers, effective with the March 1 and September 1 TCRF updates, but distribution service providers could not recover increased charges incurred prior to such updates. TCRF filings are still effective March 1 and September 1, but distribution service providers will be allowed to include wholesale transmission charges based on the effective date of the wholesale transmission rate changes. As a result, Oncor defers such increased costs as a regulatory asset until they are recovered in rates. In the second proceeding (PUCT Project No. 37519), the PUCT changed the wholesale transmission rules to allow transmission service providers to update their wholesale transmission rates twice in a calendar year, as compared to once per year under the previous rules, providing more timely recovery of incremental capital investment. Other changes included in this rule (i) tie the effective date of the biannual update portion of the rule to the effective date of the TCRF rule in PUCT Project No. 37909, (ii) require the PUCT to consider the effects of reduced regulatory lag when setting rates in the next full rate review and (iii) provide for administrative approval of uncontested interim wholesale transmission rate applications.
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Remand of 1999 Wholesale Transmission Matrix Case (PUCT Docket No. 38780)— In October 2010, the PUCT established Docket No. 38780 for the remand of Docket No. 20381, the 1999 wholesale transmission charge matrix case. A joint settlement agreement was entered into effective October 6, 2003. This settlement resolves disputes regarding wholesale transmission pricing and charges for the period of January 1997 through August 1999, the period prior to the September 1, 1999 effective date of the legislation that authorized 100% postage stamp pricing for ERCOT wholesale transmission. Since a series of appeals has become final, the 1999 matrix docket has been remanded to the PUCT to address additional issues. If the appealing parties prevail and the PUCT rules adversely with respect to these issues, Oncor could be subject to liabilities totaling up to approximately $22 million. At this time, Oncor cannot predict the outcome of these matters.
Application for 2011 Energy Efficiency Cost Recovery Factor (PUCT Docket No. 38217) — In April 2010, Oncor filed an application with the PUCT to request approval of an energy efficiency cost recovery factor (EECRF) for 2011. PUCT rules require Oncor to make an annual EECRF filing by May 1 for implementation at the beginning of the next calendar year. In September 2010, the PUCT ruled that Oncor will be allowed to recover $51 million through its 2011 EECRF, including $45 million for 2011 program costs and an $11 million performance bonus based on 2009 results partially offset by a $5 million reduction for over-recovery of 2009 costs, as compared to $54 million recovered through its 2010 EECRF. The resulting monthly charge for residential customers will be $0.91, as compared to the 2010 residential charge of $0.89 per month.
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Mine Safety Disclosures — Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act
Safety is a top priority in all our businesses, and accordingly, it is a key component of our focus on operational excellence, our employee performance reviews and employee compensation. Our health and safety program objectives are to prevent workplace accidents and ensure that all employees return home safely and comply with all regulations.
We currently own and operate 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities. These mining operations are regulated by the 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. Such citations and orders can be contested and appealed to the Federal Mine Safety and Health Review Commission (FMSHRC), which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. The number of citations, orders and proposed assessments vary depending on the size of the mine as well as other factors.
Disclosures related to specific mines pursuant to Section 1503 of the recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act sourced from data documented as of January 10, 2011 and January 17, 2011 in the MSHA Data Retrieval System for the three months and year ended December 31, 2010, respectively (except pending legal actions, which are as of December 31, 2010), are as follows:
| Three Months Ended December 31, 2010 | Year Ended December 31, 2010 | |||||||||||||||||||||||
Mine (a) | Section 104 S and S Citations (b) | Proposed MSHA Assessments ($ thousands) (c) | Pending Legal Action (d) | Section 104 S and S Citations (b) | Proposed MSHA Assessments ($ thousands) (c) | Pending Legal Action (d) | ||||||||||||||||||
Beckville | 1 | — | 1 | 8 | 18 | 1 | ||||||||||||||||||
Big Brown | — | — | 2 | 4 | 9 | 2 | ||||||||||||||||||
Kosse | 6 | — | — | 6 | 1 | — | ||||||||||||||||||
Oak Hill | 3 | 11 | 1 | 7 | 13 | 1 | ||||||||||||||||||
Sulphur Springs | 1 | 2 | 3 | 3 | 3 | 3 | ||||||||||||||||||
Tatum | — | — | 1 | — | — | 1 | ||||||||||||||||||
Three Oaks | 1 | — | 1 | 3 | 9 | 1 | ||||||||||||||||||
Winfield South | — | 1 | 1 | 1 | 4 | 1 | ||||||||||||||||||
| (a) | Excludes mines for which there were no applicable events. |
| (b) | Includes MSHA citations for health or safety standards that could significantly and substantially contribute to a serious injury if left unabated. |
| (c) | Total dollar value for proposed assessments received from MSHA for all citations and orders issued in the period ended December 31, 2010, including but not limited to Sections 104, 107 and 110 citations and orders that are not required to be reported. |
| (d) | Pending actions before the FMSHRC involving a coal or other mine. |
During the three months ended December 31, 2010, our mining operations received two citations and orders under Section 104(d) (Oak Hill mine), no citations, orders or written notices under Sections 104(b), 104(e), 107(a) or 110(b)(2) of the Mine Act, and they experienced no fatalities. During the year ended December 31, 2010, our mining operations received two citations and orders under Section 104(d) (Oak Hill Mine), one order under Section 107(a) (Beckville mine), no citations, orders or written notices under Sections 104(b), 104(e) or 110(b)(2) of the Mine Act, and they experienced no fatalities.
Summary
We cannot predict future regulatory or legislative actions or any changes in economic and securities market conditions. Such actions or changes could significantly alter our basic financial position, results of operations or cash flows.
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| Item 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Market risk is the risk that we may experience a loss in value as a result of changes in market conditions affecting factors, such as commodity prices and interest rates that may be experienced in the ordinary course of business. Our exposure to market risk is affected by a number of factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to manage interest rate risk related to debt, as well as exchange traded, over-the-counter contracts and other contractual arrangements to manage commodity price risk.
Risk Oversight
We manage the commodity price, counterparty credit and commodity-related operational risk related to the unregulated energy business within limitations established by senior management and in accordance with overall risk management policies. Interest rate risk is managed centrally by the corporate treasury function. Market risks are monitored by risk management groups that operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, Value at Risk (VaR) methodologies. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, validation of transaction capture, portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.
We have a corporate risk management organization that is headed by the Chief Financial Officer, who also functions as the Chief Risk Officer. The Chief Risk Officer, through his designees, enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits and evaluates the risks inherent in our businesses.
Commodity Price Risk
The competitive business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. We actively manage the portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices and spark spreads (differences between the market price of electricity and its cost of production).
In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. We continuously monitor the valuation of identified risks and adjust positions based on current market conditions. We strive to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.
Long-Term Hedging Program— See “Significant Activities and Events” above for a description of the program, including potential effects on reported results.
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VaR Methodology — A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio’s potential for loss given a specified confidence level and considers among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities.
A Monte Carlo simulation methodology is used to calculate VaR and is considered by management to be the most effective way to estimate changes in a portfolio’s value based on assumed market conditions for liquid markets. The use of this method requires a number of key assumptions, such as use of (i) an assumed confidence level; (ii) an assumed holding period (i.e., the time necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlation data.
Trading VaR — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts entered into for trading purposes based on a 95% confidence level and an assumed holding period of five to 60 days.
| Year Ended December 31, 2010 | Year Ended December 31, 2009 | |||||||
Month-end average Trading VaR: | $ | 3 | $ | 4 | ||||
Month-end high Trading VaR: | $ | 4 | $ | 7 | ||||
Month-end low Trading VaR: | $ | 1 | $ | 2 | ||||
VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principally hedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holding period of five to 60 days.
| Year Ended December 31, 2010 | Year Ended December 31, 2009 | |||||||
Month-end average MtM VaR: | $ | 426 | $ | 1,050 | ||||
Month-end high MtM VaR: | $ | 621 | $ | 1,470 | ||||
Month-end low MtM VaR: | $ | 321 | $ | 638 | ||||
Earnings at Risk (EaR)— This measurement estimates the potential reduction of pretax earnings for the periods presented, due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities). Transactions accounted for as cash flow hedges are also included for this measurement. A 95% confidence level and a five to 60 day holding period are assumed in determining EaR.
| Year Ended December 31, 2010 | Year Ended December 31, 2009 | |||||||
Month-end average EaR: | $ | 477 | $ | 1,088 | ||||
Month-end high EaR: | $ | 662 | $ | 1,511 | ||||
Month-end low EaR: | $ | 323 | $ | 676 | ||||
The decreases in the risk measures (MtM VaR and EaR) above reflected fewer positions in the long-term hedging program due to settlement upon maturity, lower market volatility and lower underlying commodity prices.
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Interest Rate Risk
The table below provides information concerning our financial instruments as of December 31, 2010 and 2009 that are sensitive to changes in interest rates, which include debt obligations and interest rate swaps. We have entered into interest rate swaps under which we have exchanged the difference between fixed-rate and variable-rate interest amounts calculated with reference to specified notional principal amounts at dates that generally coincide with interest payments under our credit facilities. In addition, in connection with entering into certain interest rate basis swaps to further reduce fixed borrowing costs, we have changed the variable interest rate terms of certain TCEH debt from three-month LIBOR to one-month LIBOR, as discussed in Note 11 to Financial Statements. The weighted average interest rate presented is based on the rate in effect at the reporting date. Capital leases and the effects of unamortized premiums and discounts and fair value hedges are excluded from the table. See Note 11 to Financial Statements for a discussion of changes in debt obligations.
| Expected Maturity Date | ||||||||||||||||||||||||||||||||||||||||
| (millions of dollars, except percentages) | ||||||||||||||||||||||||||||||||||||||||
| 2011 | 2012 | 2013 | 2014 | 2015 | There- After | 2010 Total Carrying Amount | 2010 Total Fair Value | 2009 Total Carrying Amount | 2009 Total Fair Value | |||||||||||||||||||||||||||||||
Long-term debt (including current maturities): | ||||||||||||||||||||||||||||||||||||||||
Fixed rate debt amount (a) | $ | 446 | $ | 32 | $ | 91 | $ | 483 | $ | 3,187 | $ | 9,798 | $ | 14,037 | $ | 10,052 | $ | 20,861 | $ | 17,296 | ||||||||||||||||||||
Average interest rate | 5.86 | % | 8.17 | % | 7.24 | % | 5.66 | % | 10.24 | % | 10.32 | % | 9.98 | % | 8.95 | % | ||||||||||||||||||||||||
Variable rate debt amount | $ | 205 | $ | 205 | $ | 205 | $ | 20,563 | $ | — | $ | 205 | $ | 21,383 | $ | 16,542 | $ | 21,608 | $ | 17,463 | ||||||||||||||||||||
Average interest rate | 3.76 | % | 3.76 | % | 3.76 | % | 3.76 | % | — | % | 0.32 | % | 3.73 | % | 3.71 | % | ||||||||||||||||||||||||
Total debt | $ | 651 | $ | 237 | $ | 296 | $ | 21,046 | $ | 3,187 | $ | 10,003 | $ | 35,420 | $ | 26,594 | $ | 42,469 | $ | 34,759 | ||||||||||||||||||||
Debt swapped to fixed: | ||||||||||||||||||||||||||||||||||||||||
Amount | $ | 600 | $ | 2,600 | $ | 3,600 | $ | 9,000 | $ | — | $ | — | $ | 15,800 | $ | 16,300 | ||||||||||||||||||||||||
Average pay rate | 7.57 | % | 7.99 | % | 7.60 | % | 8.18 | % | — | — | 7.99 | % | 7.98 | % | ||||||||||||||||||||||||||
Average receive rate | 3.79 | % | 3.79 | % | 3.79 | % | 3.79 | % | — | — | 3.79 | % | 3.74 | % | ||||||||||||||||||||||||||
Variable basis swaps: | ||||||||||||||||||||||||||||||||||||||||
Amount | $ | 5,450 | $ | 7,200 | $ | 1,500 | $ | 1,050 | $ | — | $ | — | $ | 15,200 | $ | 16,250 | ||||||||||||||||||||||||
Average pay rate | 0.32 | % | 0.33 | % | 0.29 | % | 0.33 | % | — | — | 0.32 | % | 0.33 | % | ||||||||||||||||||||||||||
Average receive rate | 0.26 | % | 0.26 | % | 0.26 | % | 0.26 | % | — | — | 0.26 | % | 0.24 | % | ||||||||||||||||||||||||||
| (a) | Reflects the remarketing date and not the maturity date for certain debt that is subject to mandatory tender for remarketing prior to maturity. See Note 11 to Financial Statements for details concerning long-term debt subject to mandatory tender for remarketing. |
As of December 31, 2010, the potential reduction of annual pretax earnings due to a one percentage point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $45 million, taking into account the interest rate swaps discussed in Note 11 to Financial Statements.
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Credit Risk
Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty’s financial condition, credit rating and other quantitative and qualitative credit criteria and specify authorized risk mitigation tools including, but not limited to, use of standardized master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties’ financial strength, measurement of current and potential future exposures and contract language that provides rights for netting and set-off. Credit enhancements such as parental guarantees, letters of credit, surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to assess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering into an agreement with a counterparty that creates exposure. Additionally, we have established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material adverse changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. This process can result in the subsequent reduction of the credit limit or a request for additional financial assurances.
Credit Exposure — Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions (before credit collateral) arising from commodity contracts and hedging and trading activities totaled $2.869 billion as of December 31, 2010. The components of this exposure are discussed in more detail below.
Assets subject to credit risk as of December 31, 2010 include $615 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $70 million. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.
The remaining credit exposure arises from wholesale trade receivables, commodity contracts and hedging and trading activities, including interest rate hedging. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. As of December 31, 2010, the exposure to credit risk from these counterparties totaled $2.254 billion taking into account the standardized master netting contracts and agreements described above but before taking into account $648 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $1.606 billion increased $309 million in the year ended December 31, 2010, reflecting the increase in derivative assets related to the long-term hedging program due to the decline in forward natural gas prices, partially offset by the return of the $400 million in collateral discussed in Note 17 to Financial Statements and the increase in derivative liabilities related to interest rate swaps due to lower interest rates.
Of this $1.606 billion net exposure, essentially all is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and our internal credit evaluation process. Those customers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties on this basis.
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The following table presents the distribution of credit exposure as of December 31, 2010 arising from wholesale trade receivables, commodity contracts and hedging and trading activities. This credit exposure represents wholesale trade accounts receivable and net asset positions on the balance sheet arising from hedging and trading activities after taking into consideration netting provisions within each contract, setoff provisions in the event of default and any master netting contracts with counterparties. See Note 17 to Financial Statements for further discussion of portions of this exposure related to activities marked-to-market in the financial statements.
| Gross Exposure by Maturity | ||||||||||||||||||||||||||||
| Exposure Before Credit Collateral | Credit Collateral | Net Exposure | 2 years or less | Between 2-5 years | Greater than 5 years | Total | ||||||||||||||||||||||
Investment grade | $ | 2,229 | $ | 646 | $ | 1,583 | $ | 1,597 | $ | 632 | $ | — | $ | 2,229 | ||||||||||||||
Noninvestment grade | 25 | 2 | 23 | 26 | (1 | ) | — | 25 | ||||||||||||||||||||
Totals | $ | 2,254 | $ | 648 | $ | 1,606 | $ | 1,623 | $ | 631 | $ | — | $ | 2,254 | ||||||||||||||
Investment grade | 98.9 | % | 98.6 | % | ||||||||||||||||||||||||
Noninvestment grade | 1.1 | % | 1.4 | % | ||||||||||||||||||||||||
In addition to the exposures in the table above, contracts classified as “normal” purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform. Nonperformance could have a material adverse impact on future results of operations, financial condition and cash flows.
Significant (10% or greater) concentration of credit exposure exists with three counterparties, which represented 41%, 35% and 12% of the net $1.606 billion exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and the importance of our business relationship with the counterparty. However, this concentration increases the risk that a default would have a material effect on results of operations.
With respect to credit risk related to the long-term hedging program, essentially all of the transaction volumes are with counterparties with an A credit rating or better. However, there is current and potential credit concentration risk related to the limited number of counterparties that comprise the substantial majority of the program with such counterparties being in the banking and financial sector. The transactions with these counterparties contain certain credit rating provisions that would require the counterparties to post collateral in the event of a material downgrade in the credit rating of the counterparties. An event of default by one or more hedge counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us. While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through the various ongoing risk management measures described above.
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FORWARD-LOOKING STATEMENTS
This report and other presentations made by us contain “forward-looking statements.” All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that we expect or anticipate to occur in the future, including such matters as projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as “intends,” “plans,” “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “should,” “projection,” “target,” “goal,” “objective” and “outlook”), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors under Item 1A, “Risk Factors” and the discussion under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report and the following important factors, among others, that could cause our actual results to differ materially from those projected in such forward-looking statements:
| • | prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, the FERC, the NERC, the TRE, the PUCT, the RRC, the NRC, the EPA, the TCEQ and the CFTC, with respect to, among other things: |
| • | allowed prices; |
| • | allowed rates of return; |
| • | permitted capital structure; |
| • | industry, market and rate structure; |
| • | purchased power and recovery of investments; |
| • | operations of nuclear generating facilities; |
| • | operations of fossil-fueled generating facilities; |
| • | operations of mines; |
| • | acquisition and disposal of assets and facilities; |
| • | development, construction and operation of facilities; |
| • | decommissioning costs; |
| • | present or prospective wholesale and retail competition; |
| • | changes in tax laws and policies; |
| • | changes in and compliance with environmental and safety laws and policies, including climate change initiatives, and |
| • | clearing over the counter derivatives through exchanges and posting of cash collateral therewith; |
| • | legal and administrative proceedings and settlements; |
| • | general industry trends; |
| • | economic conditions, including the impact of a recessionary environment; |
| • | our ability to attract and retain profitable customers; |
| • | our ability to profitably serve our customers; |
| • | restrictions on competitive retail pricing; |
| • | changes in wholesale electricity prices or energy commodity prices; |
| • | changes in prices of transportation of natural gas, coal, crude oil and refined products; |
| • | unanticipated changes in market heat rates in the ERCOT electricity market; |
| • | our ability to effectively hedge against unfavorable commodity prices, market heat rates and interest rates; |
| • | weather conditions and other natural phenomena, and acts of sabotage, wars or terrorist activities; |
| • | unanticipated population growth or decline, or changes in market demand and demographic patterns, particularly in ERCOT; |
| • | changes in business strategy, development plans or vendor relationships; |
| • | access to adequate transmission facilities to meet changing demands; |
| • | unanticipated changes in interest rates, commodity prices, rates of inflation or foreign exchange rates; |
| • | unanticipated changes in operating expenses, liquidity needs and capital expenditures; |
| • | commercial bank market and capital market conditions and the potential impact of disruptions in US and international credit markets; |
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| • | the willingness of our lenders to amend and extend the maturities of our debt agreements and the terms and conditions of any such amendments; |
| • | access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds in capital markets; |
| • | financial restrictions placed on us by the agreements governing our debt instruments; |
| • | our ability to generate sufficient cash flow to make interest payments on, or refinance, our debt instruments; |
| • | our ability to successfully execute our liability management program; |
| • | competition for new energy development and other business opportunities; |
| • | inability of various counterparties to meet their obligations with respect to our financial instruments; |
| • | changes in technology used by and services offered by us; |
| • | changes in electricity transmission that allow additional electricity generation to compete with our generation assets; |
| • | significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur; |
| • | changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and OPEB, and future funding requirements related thereto; |
| • | changes in assumptions used to estimate future executive compensation payments; |
| • | hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards; |
| • | significant changes in critical accounting policies; |
| • | actions by credit rating agencies; |
| • | our ability to effectively execute our operational strategy, and |
| • | our ability to implement cost reduction initiatives. |
Any forward-looking statement speaks only as of the date on which it is made, and except as may be required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. As such, you should not unduly rely on such forward-looking statements.
INDUSTRY AND MARKET INFORMATION
The industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by ERCOT, the PUCT and NYMEX. We did not commission any of these publications or reports. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data and make no representation as to the accuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions regarding general economic growth are used in preparing the forecasts included in this report. Similarly, while we believe that such internal and external research is reliable, it has not been verified by any independent sources, and we make no assurances that the predictions contained therein are accurate.
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| Item 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Energy Future Holdings Corp.
Dallas, Texas
We have audited the accompanying consolidated balance sheets of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) as of December 31, 2010 and 2009, and the related statements of consolidated income (loss), comprehensive income (loss), cash flows and equity for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of EFH Corp.’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Energy Future Holdings Corp. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Notes 1 and 2 to the consolidated financial statements, EFH Corp. adopted amended consolidation accounting standards related to variable interest entities, and as also discussed in Notes 1 and 10 to the consolidated financial statements, EFH Corp. adopted amended guidance regarding transfers of financial assets effective January 1, 2010, on a prospective basis.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), EFH Corp.’s internal control over financial reporting as of December 31, 2010, based on the criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 17, 2011 expressed an unqualified opinion on EFH Corp.’s internal control over financial reporting.
| /s/ Deloitte & Touche LLP |
| Dallas, Texas |
| February 17, 2011 |
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME (LOSS)
(Millions of Dollars)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Operating revenues | $ | 8,235 | $ | 9,546 | $ | 11,364 | ||||||
Fuel, purchased power costs and delivery fees | (4,371 | ) | (2,878 | ) | (4,595 | ) | ||||||
Net gain from commodity hedging and trading activities | 2,161 | 1,736 | 2,184 | |||||||||
Operating costs | (837 | ) | (1,598 | ) | (1,503 | ) | ||||||
Depreciation and amortization | (1,407 | ) | (1,754 | ) | (1,610 | ) | ||||||
Selling, general and administrative expenses | (751 | ) | (1,068 | ) | (957 | ) | ||||||
Franchise and revenue-based taxes | (106 | ) | (359 | ) | (363 | ) | ||||||
Impairment of goodwill (Note 4) | (4,100 | ) | (90 | ) | (8,860 | ) | ||||||
Other income (Note 9) | 2,051 | 204 | 80 | |||||||||
Other deductions (Note 9) | (31 | ) | (97 | ) | (1,301 | ) | ||||||
Interest income | 10 | 45 | 27 | |||||||||
Interest expense and related charges (Note 24) | (3,554 | ) | (2,912 | ) | (4,935 | ) | ||||||
Income (loss) before income taxes and equity in earnings of unconsolidated subsidiaries | (2,700 | ) | 775 | (10,469 | ) | |||||||
Income tax (expense) benefit (Note 8) | (389 | ) | (367 | ) | 471 | |||||||
Equity in earnings of unconsolidated subsidiaries (net of tax) (Note 2) | 277 | — | — | |||||||||
Net income (loss) | (2,812 | ) | 408 | (9,998 | ) | |||||||
Net (income) loss attributable to noncontrolling interests | — | (64 | ) | 160 | ||||||||
Net income (loss) attributable to EFH Corp. | $ | (2,812 | ) | $ | 344 | $ | (9,838 | ) | ||||
See Notes to Financial Statements.
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(Millions of Dollars)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Net income (loss) | $ | (2,812 | ) | $ | 408 | $ | (9,998 | ) | ||||
Other comprehensive income (loss), net of tax effects: | ||||||||||||
Effects related to pension and other retirement benefit obligations (net of tax benefit of $8, $20 and $69) (Note 20) | (13 | ) | (40 | ) | (84 | ) | ||||||
Cash flow hedges: | ||||||||||||
Net decrease in fair value of derivatives (net of tax benefit of $—, $10 and $99) | — | (20 | ) | (183 | ) | |||||||
Derivative value net loss related to hedged transactions recognized during the period and reported in net income (loss) (net of tax benefit of $31, $72 and $66) | 59 | 130 | 122 | |||||||||
Total effect of cash flow hedges | 59 | 110 | (61 | ) | ||||||||
Total other comprehensive income (loss) | 46 | 70 | (145 | ) | ||||||||
Comprehensive income (loss) | (2,766 | ) | 478 | (10,143 | ) | |||||||
Comprehensive (income) loss attributable to noncontrolling interests | — | (64 | ) | 160 | ||||||||
Comprehensive income (loss) attributable to EFH Corp. | $ | (2,766 | ) | $ | 414 | $ | (9,983 | ) | ||||
See Notes to Financial Statements.
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Cash flows — operating activities | ||||||||||||
Net income (loss) | $ | (2,812 | ) | $ | 408 | $ | (9,998 | ) | ||||
Adjustments to reconcile net income to cash provided by operating activities: | ||||||||||||
Depreciation and amortization | 1,778 | 2,172 | 2,070 | |||||||||
Deferred income tax expense (benefit) – net | 604 | 253 | (477 | ) | ||||||||
Impairment of goodwill (Note 4) | 4,100 | 90 | 8,860 | |||||||||
Debt extinguishment gains (Note 11) | (1,814 | ) | (87 | ) | — | |||||||
Unrealized net gains from mark-to-market valuations of commodity positions | (1,221 | ) | (1,225 | ) | (2,329 | ) | ||||||
Interest expense on toggle notes payable in additional principal (Notes 11 and 24) | 446 | 524 | 83 | |||||||||
Equity in earnings of unconsolidated subsidiaries | (277 | ) | — | — | ||||||||
Unrealized net (gains) losses from mark-to-market valuations of interest rate swaps (Note 11) | 207 | (696 | ) | 1,477 | ||||||||
Distributions of earnings from unconsolidated subsidiaries | 169 | — | — | |||||||||
Gain on termination of long-term power sales contract (Note 9) | (116 | ) | — | — | ||||||||
Bad debt expense (Note 10) | 108 | 113 | 81 | |||||||||
Losses on dedesignated cash flow hedges (interest rate swaps) | 87 | 184 | 66 | |||||||||
Net gain on sale of assets | (81 | ) | (5 | ) | (1 | ) | ||||||
Stock-based incentive compensation expense | 19 | 14 | 30 | |||||||||
Reversal of reserves recorded in purchase accounting (Note 9) | — | (44 | ) | — | ||||||||
Impairment of land | — | 34 | — | |||||||||
Write off of regulatory assets (Note 24) | — | 25 | — | |||||||||
Impairment of emission allowances intangible assets (Note 4) | — | — | 501 | |||||||||
Impairment of trade name intangible asset (Note 4) | — | — | 481 | |||||||||
Impairment of natural gas-fueled generation facilities (Note 5) | — | — | 229 | |||||||||
Charge related to Lehman bankruptcy (Note 9) | — | — | 26 | |||||||||
Other, net | 11 | (4 | ) | (20 | ) | |||||||
Changes in operating assets and liabilities: | ||||||||||||
Accounts receivable – trade | 258 | (125 | ) | (505 | ) | |||||||
Impact of accounts receivable securitization program (Note 10) | (383 | ) | (33 | ) | 53 | |||||||
Inventories | (6 | ) | (59 | ) | (21 | ) | ||||||
Accounts payable – trade | (93 | ) | (141 | ) | 385 | |||||||
Commodity and other derivative contractual assets and liabilities | (44 | ) | (64 | ) | (28 | ) | ||||||
Margin deposits – net | 132 | 248 | 595 | |||||||||
Deferred advanced metering system revenues (Note 24) | — | 57 | — | |||||||||
Other – net assets | 151 | (43 | ) | 440 | ||||||||
Other – net liabilities | (117 | ) | 115 | (493 | ) | |||||||
Cash provided by operating activities | $ | 1,106 | $ | 1,711 | $ | 1,505 | ||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.)
(Millions of Dollars)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Cash flows — financing activities | ||||||||||||
Issuances of long-term debt/securities (Note 11): | ||||||||||||
Pollution control revenue bonds | $ | — | $ | — | $ | 242 | ||||||
Oncor long-term debt | — | — | 1,500 | |||||||||
Other long-term debt | 853 | 522 | 1,443 | |||||||||
Common stock | — | — | 34 | |||||||||
Repayments/repurchases of long-term debt/securities (Note 11): | ||||||||||||
Pollution control revenue bonds | — | — | (242 | ) | ||||||||
Other long-term debt | (1,351 | ) | (396 | ) | (925 | ) | ||||||
Common stock | — | — | (3 | ) | ||||||||
Net short-term borrowings under accounts receivable securitization program (Note 10) | 96 | — | — | |||||||||
Increase (decrease) in other short-term borrowings (Note 11) | 172 | 332 | (481 | ) | ||||||||
Proceeds from sale of noncontrolling interests, net of transaction costs (Note 14) | — | — | 1,253 | |||||||||
Decrease in note payable to unconsolidated subsidiary | (37 | ) | — | — | ||||||||
Contributions from noncontrolling interests | 32 | 48 | — | |||||||||
Distributions paid to noncontrolling interests | — | (56 | ) | (2 | ) | |||||||
Debt exchange and issuance costs | (62 | ) | (49 | ) | (21 | ) | ||||||
Other, net | 33 | 21 | 39 | |||||||||
Cash provided by (used in) financing activities | $ | (264 | ) | $ | 422 | $ | 2,837 | |||||
Cash flows — investing activities | ||||||||||||
Capital expenditures | (838 | ) | (2,348 | ) | (2,849 | ) | ||||||
Nuclear fuel purchases | (106 | ) | (197 | ) | (166 | ) | ||||||
Money market fund redemptions (investments) | — | 142 | (142 | ) | ||||||||
Investment redeemed/(posted) with derivative counterparty (Note 17) | 400 | (400 | ) | — | ||||||||
Reduction of letter of credit facility deposited with trustee (Note 11) | — | 115 | — | |||||||||
Reduction of restricted cash related to pollution control revenue bonds | — | — | 29 | |||||||||
Other changes in restricted cash | (33 | ) | 9 | 1 | ||||||||
Proceeds from sale of assets | 147 | 42 | 80 | |||||||||
Proceeds from sale of environmental allowances and credits | 12 | 19 | 39 | |||||||||
Purchases of environmental allowances and credits | (30 | ) | (19 | ) | (34 | ) | ||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 974 | 3,064 | 1,623 | |||||||||
Investments in nuclear decommissioning trust fund securities | (990 | ) | (3,080 | ) | (1,639 | ) | ||||||
Cash settlements related to outsourcing contract termination (Note 19) | — | — | 70 | |||||||||
Settlement of loan (Note 19) | — | — | 25 | |||||||||
Other, net | (4 | ) | 20 | 29 | ||||||||
Cash used in investing activities | $ | (468 | ) | $ | (2,633 | ) | $ | (2,934 | ) | |||
Net change in cash and cash equivalents | 374 | (500 | ) | 1,408 | ||||||||
Effect of deconsolidation of Oncor Holdings | (29 | ) | — | — | ||||||||
Cash and cash equivalents — beginning balance | 1,189 | 1,689 | 281 | |||||||||
Cash and cash equivalents — ending balance | $ | 1,534 | $ | 1,189 | $ | 1,689 | ||||||
See Notes to Financial Statements.
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
| December 31, | ||||||||
| 2010 | 2009 (see Note 2) | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents (Note 1) | $ | 1,534 | $ | 1,189 | ||||
Investment posted with counterparty (Note 17) | — | 425 | ||||||
Restricted cash (Note 24) | 33 | 48 | ||||||
Trade accounts receivable — net (2010 includes $612 in pledged amounts related to a VIE (Notes 3 and 10)) | 999 | 1,260 | ||||||
Inventories (Note 24) | 395 | 485 | ||||||
Commodity and other derivative contractual assets (Note 17) | 2,732 | 2,391 | ||||||
Accumulated deferred income taxes (Note 8) | — | 5 | ||||||
Margin deposits related to commodity positions | 166 | 187 | ||||||
Other current assets | 60 | 136 | ||||||
Total current assets | 5,919 | 6,126 | ||||||
Restricted cash (Note 24) | 1,135 | 1,149 | ||||||
Receivables from unconsolidated subsidiary (Note 22) | 1,463 | — | ||||||
Investments in unconsolidated subsidiaries (Note 2) | 5,544 | 44 | ||||||
Other investments (Note 18) | 697 | 706 | ||||||
Property, plant and equipment — net (Note 24) | 20,366 | 30,108 | ||||||
Goodwill (Note 4) | 6,152 | 14,316 | ||||||
Identifiable intangible assets — net (Note 4) | 2,400 | 2,876 | ||||||
Regulatory assets — net (Note 24) | — | 1,959 | ||||||
Commodity and other derivative contractual assets (Note 17) | 2,071 | 1,533 | ||||||
Other noncurrent assets, principally unamortized debt issuance costs | 641 | 845 | ||||||
Total assets | $ | 46,388 | $ | 59,662 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Short-term borrowings (2010 includes $96 related to a VIE (Notes 3 and 11)) | $ | 1,221 | $ | 1,569 | ||||
Long-term debt due currently (Note 11) | 669 | 417 | ||||||
Trade accounts payable | 681 | 896 | ||||||
Payables due to unconsolidated subsidiary (Note 22) | 254 | — | ||||||
Commodity and other derivative contractual liabilities (Note 17) | 2,283 | 2,392 | ||||||
Margin deposits related to commodity positions | 631 | 520 | ||||||
Accumulated deferred income taxes (Note 8) | 11 | — | ||||||
Accrued interest | 411 | 526 | ||||||
Other current liabilities | 442 | 744 | ||||||
Total current liabilities | 6,603 | 7,064 | ||||||
Accumulated deferred income taxes (Note 8) | 5,350 | 6,131 | ||||||
Investment tax credits | — | 37 | ||||||
Commodity and other derivative contractual liabilities (Note 17) | 869 | 1,060 | ||||||
Notes or other liabilities due to unconsolidated subsidiary (Note 22) | 384 | — | ||||||
Long-term debt, less amounts due currently (Note 11) | 34,226 | 41,440 | ||||||
Other noncurrent liabilities and deferred credits (Note 24) | 4,867 | 5,766 | ||||||
Total liabilities | 52,299 | 61,498 | ||||||
Commitments and Contingencies (Note 12) | ||||||||
Equity (Note 13): | ||||||||
Common stock (shares outstanding 2010 — 1,671,812,118; 2009 — 1,668,065,133) | 2 | 2 | ||||||
Additional paid-in capital | 7,937 | 7,914 | ||||||
Retained earnings (deficit) | (13,666 | ) | (10,854 | ) | ||||
Accumulated other comprehensive income (loss) | (263 | ) | (309 | ) | ||||
EFH Corp. shareholders’ equity | (5,990 | ) | (3,247 | ) | ||||
Noncontrolling interests in subsidiaries | 79 | 1,411 | ||||||
Total equity | (5,911 | ) | (1,836 | ) | ||||
Total liabilities and equity | $ | 46,388 | $ | 59,662 | ||||
See Notes to Financial Statements.
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED EQUITY
(Millions of Dollars)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Common stock stated value of $0.001 effective May 2009 (number of authorized shares — 2,000,000,000): | ||||||||||||
Balance as of beginning of period | $ | 2 | $ | — | $ | — | ||||||
Effects of shareholder actions related to stated value of common stock | — | 2 | — | |||||||||
Balance as of end of period (number of shares outstanding: 2010 — 1,671,812,118; 2009 — 1,668,065,133; 2008 — 1,667,149,663 | 2 | 2 | — | |||||||||
Additional paid-in capital: | ||||||||||||
Balance as of beginning of period | 7,914 | 7,904 | 8,279 | |||||||||
Effects of stock-based incentive compensation plans | 24 | 11 | 29 | |||||||||
Effects of shareholder actions related to stated value of common stock | — | (2 | ) | — | ||||||||
Effect of sale of noncontrolling interests (Note 13) | — | — | (406 | ) | ||||||||
Common stock repurchases | (2 | ) | — | — | ||||||||
Other | 1 | 1 | 2 | |||||||||
Balance as of end of period | 7,937 | 7,914 | 7,904 | |||||||||
Retained earnings (deficit): | ||||||||||||
Balance as of beginning of period | (10,854 | ) | (11,198 | ) | (1,360 | ) | ||||||
Net income (loss) attributable to EFH Corp. | (2,812 | ) | 344 | (9,838 | ) | |||||||
Balance as of end of period | (13,666 | ) | (10,854 | ) | (11,198 | ) | ||||||
Accumulated other comprehensive income (loss), net of tax effects: | ||||||||||||
Pension and other postretirement employee benefit liability adjustments: | ||||||||||||
Balance as of beginning of period | (181 | ) | (141 | ) | (57 | ) | ||||||
Change in unrecognized gains (losses) related to pension and other retirement benefit costs | (13 | ) | (40 | ) | (84 | ) | ||||||
Balance as of end of period | (194 | ) | (181 | ) | (141 | ) | ||||||
Amounts related to cash flow hedges: | ||||||||||||
Balance as of beginning of period | (128 | ) | (238 | ) | (177 | ) | ||||||
Change during the period | 59 | 110 | (61 | ) | ||||||||
Balance as of end of period | (69 | ) | (128 | ) | (238 | ) | ||||||
Total accumulated other comprehensive income (loss) as of end of period | (263 | ) | (309 | ) | (379 | ) | ||||||
EFH Corp. shareholders’ equity as of end of period (Note 13) | (5,990 | ) | (3,247 | ) | (3,673 | ) | ||||||
Noncontrolling interests in subsidiaries (Note 14): | ||||||||||||
Balance as of beginning of period | 1,411 | 1,355 | — | |||||||||
Net income (loss) attributable to noncontrolling interests | — | 64 | (160 | ) | ||||||||
Effect of deconsolidation of Oncor Holdings (Notes 1 and 3) | (1,363 | ) | — | — | ||||||||
Investments by noncontrolling interests | 32 | 48 | 1,253 | |||||||||
Effect of sale of noncontrolling interests | — | — | 265 | |||||||||
Distributions to noncontrolling interests | — | (56 | ) | (2 | ) | |||||||
Other | (1 | ) | — | (1 | ) | |||||||
Noncontrolling interests in subsidiaries as of end of period | 79 | 1,411 | 1,355 | |||||||||
Total equity as of end of period | $ | (5,911 | ) | $ | (1,836 | ) | $ | (2,318 | ) | |||
See Notes to Financial Statements.
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| 1. | BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES |
Description of Business
EFH Corp., a Texas corporation, is a Dallas-based holding company with operations consisting principally of our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority (approximately 80%) owned subsidiary engaged in regulated electricity transmission and distribution operations in Texas. See Note 3 regarding the deconsolidation of Oncor (and it majority owner, Oncor Holdings) as a result of amended consolidation accounting standards related to variable interest entities (VIEs) effective January 1, 2010.
On October 10, 2007, EFH Corp. completed its Merger with Merger Sub. As a result of the Merger, EFH Corp. became a subsidiary of Texas Holdings, which is controlled by the Sponsor Group.
References in this report to “we,” “our,” “us” and “the company” are to EFH Corp. and/or its subsidiaries, TCEH and/or its subsidiaries, or Oncor and/or its subsidiary as apparent in the context. See “Glossary” for other defined terms.
Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. Such measures include, among other things: the sale of a 19.75% equity interest in Oncor to Texas Transmission in November 2008; maintenance of separate books and records for the Oncor Ring-Fenced Entities; Oncor’s board of directors being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or contractual obligations of any member of the Texas Holdings Group. Moreover, Oncor’s operations are conducted, and its cash flows managed, independently from the Texas Holdings Group.
See Note 14 for discussion of noncontrolling interests sold by Oncor in November 2008.
We have two reportable segments: the Competitive Electric segment, which is comprised principally of TCEH, and the Regulated Delivery segment, which is comprised of Oncor Holdings and its subsidiaries. See Note 23 for further information concerning reportable business segments.
Basis of Presentation
The consolidated financial statements have been prepared in accordance with US GAAP. The consolidated financial statements have been prepared on the same basis as the audited financial statements included in the 2009 Form 10-K with the exception of the prospective adoption of amended guidance regarding consolidation accounting standards related to VIEs that resulted in the deconsolidation of Oncor Holdings as discussed in Note 3 and amended guidance regarding transfers of financial assets that resulted in the accounts receivable securitization program no longer being accounted for as a sale of accounts receivable and the funding under the program now reported as short-term borrowings as discussed in Note 10. All intercompany items and transactions have been eliminated in consolidation. All acquisitions of outstanding debt for cash, including notes that had been issued in lieu of cash interest, are presented in the financing activities section of the statement of cash flows. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.
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Use of Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities as of the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates or assumptions during the current year.
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of electricity, natural gas and other commodities and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage our commodity price and interest rate risks. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses, unless the criteria for certain exceptions are met, and an offsetting derivative asset or liability is recorded in the balance sheet. This recognition is referred to as “mark-to-market” accounting. The fair values of our unsettled derivative instruments under mark-to-market accounting are reported in the balance sheet as commodity and other derivative contractual assets or liabilities. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 15 and 17 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. Under the election criteria of accounting standards related to derivative instruments and hedging activities, we may elect the “normal” purchase and sale exemption. A commodity-related derivative contract may be designated as a “normal” purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.
Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for “hedge accounting,” which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met. A cash flow hedge mitigates the risk associated with the variability of the future cash flows related to an asset or liability (e.g., a forecasted sale of electricity in the future at market prices or the payment of interest related to variable rate debt), while a fair value hedge mitigates risk associated with fixed future cash flows (e.g., debt with fixed interest rate payments). In accounting for changes in the fair value of cash flow hedges, derivative assets and liabilities are recorded on the balance sheet with an offset to other comprehensive income or loss to the extent the hedges are effective and the hedged transaction remains probable of occurring. If the hedged transaction becomes probable of not occurring, hedge accounting is discontinued and the amount recorded in other comprehensive income is immediately reclassified into net income. If the relationship between the hedge and the hedged transaction ceases to exist or is dedesignated, hedge accounting is discontinued, and the amounts recorded in other comprehensive income are recognized as the previously hedged transaction impacts earnings. Changes in value of fair value hedges are recorded as derivative assets or liabilities with an offset to net income, and the carrying value of the related asset or liability (hedged item) is adjusted for changes in fair value with an offset to net income. If the fair value hedge is settled prior to the maturity of the hedged item, the cumulative fair value gain or loss associated with the hedge is amortized into income over the remaining life of the hedged item. In the statement of cash flow, the effects of settlements of derivative instruments are classified consistent with the related hedged transactions.
To qualify for hedge accounting, a hedge must be considered highly effective in offsetting changes in fair value of the hedged item. Assessment of the hedge’s effectiveness is tested at least quarterly throughout its term to continue to qualify for hedge accounting. Changes in fair value that represent hedge ineffectiveness, even if the hedge continues to be assessed as effective, are immediately recognized in net income. Ineffectiveness is generally measured as the cumulative excess, if any, of the change in value of the hedging instrument over the change in value of the hedged item. See Notes 11 and 17 for additional information concerning hedging activity.
At December 31, 2010 and 2009, there were no derivative positions accounted for as cash flow or fair value hedges. Accumulated other comprehensive income includes amounts related to interest rate swaps previously designated as cash flow hedges that will be recognized in net income as the hedged transactions impact net income (see Note 11).
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Realized and unrealized gains and losses from transacting in energy-related derivative instruments are primarily reported in the income statement in net gain (loss) from commodity hedging and trading activities. In accordance with accounting rules, upon settlement of physical derivative sales and purchase contracts that are marked-to-market in net income, related wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, instead of the contract price. As a result, this noncash difference between market and contract prices is included in the operating revenues and fuel and purchased power costs and delivery fees line items of the income statement, with offsetting amounts included in net gain (loss) from commodity hedging and trading activities.
Revenue Recognition
We record revenue from electricity sales and delivery service under the accrual method of accounting. Revenues are recognized when electricity or delivery services are provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the revenues earned from the meter reading date to the end of the period (unbilled revenue).
We report physically delivered commodity sales and purchases in the income statement on a gross basis in revenues and fuel, purchased power and delivery fees, respectively, and we report all other commodity related contracts and financial instruments (primarily derivatives) in the income statement on a net basis in net gain/(loss) from commodity hedging and trading activities. As part of ERCOT’s transition to a nodal wholesale market effective December 1, 2010, volumes under nontrading bilateral purchase and sales contracts, including contracts intended as hedges, are no longer scheduled as physical power with ERCOT. Accordingly, unless the volumes represent physical deliveries to customers or purchases from counterparties, effective with the nodal market implementation, such contracts are reported net in the income statement in net gain/(loss) from commodity hedging and trading activities instead of reported gross as wholesale revenues or purchased power costs. As a result of the changes in wholesale market operations, 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, and if volumes delivered to our retail and wholesale customers exceed our generation volumes, we record additional purchased power costs. The additional wholesale revenues or purchased power costs are offset in net gain/(loss) from commodity hedging and trading activities.
Impairment of Long-Lived Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 5 for details of the impairment of the natural gas-fueled generation facilities recorded in 2008.
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. Indicators that should be evaluated for possible impairment of investments include recurring operating losses of the investee or fair value measures that are less than carrying value. Any impairment recognition is based on fair value that is not reflective of temporary conditions. Fair value is determined primarily by discounted long-term cash flows, supported by available market valuations, if applicable.
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 4 for additional information.
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Goodwill and Intangible Assets with Indefinite Lives
We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually (as of December 1). See Note 4 for details of goodwill and intangible assets with indefinite lives, including discussion of fair value determinations and impairments of goodwill and trade name intangible assets recorded in 2010, 2009 and 2008.
Amortization of Nuclear Fuel
Amortization of nuclear fuel is calculated on the units-of-production method and is reported as fuel costs.
Major Maintenance
Major maintenance costs incurred during generation plant outages and the costs of other maintenance activities are charged to expense as incurred and reported as operating costs.
Defined Benefit Pension Plans and Other Postretirement Employee Benefit Plans
We offer pension benefits based on either a traditional defined benefit formula or a cash balance formula and also offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from the company. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. The pension and OPEB accrued benefit obligations reported in the balance sheet are in accordance with accounting standards related to employers’ accounting for defined benefit pension and other postretirement plans. See Note 20 for additional information regarding pension and OPEB plans.
Stock-Based Incentive Compensation
Our 2007 Stock Incentive Plan authorizes discretionary grants to directors, officers and qualified managerial employees of EFH Corp. or its affiliates of non-qualified stock options, stock appreciation rights, restricted shares, shares of common stock, the opportunity to purchase shares of common stock and other stock-based awards. Stock-based compensation expense is recognized over the vesting period based on the grant-date fair value of those awards. See Note 21 for information regarding stock-based incentive compensation.
Sales and Excise Taxes
Sales and excise taxes are accounted for as a “pass through” item on the balance sheet; i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction.
Franchise and Revenue-Based Taxes
Unlike sales and excise taxes, franchise and gross receipt taxes are not a “pass through” item. These taxes are assessed to us by state and local government bodies, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and gross receipt taxes, but we are not acting as an agent to collect the taxes from customers.
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Income Taxes
We file a consolidated federal income tax return, and federal income taxes are calculated for our subsidiaries substantially as if the entities file separate income tax returns. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities. Effective with the sale of noncontrolling interests in Oncor in 2008 (see Note 14), Oncor became a partnership for US federal income tax purposes, and we provide deferred income taxes on the difference between the book and tax basis of our investment in Oncor. Investment tax credits related to Oncor’s regulated operations are deferred and amortized over the lives of the related properties in accordance with regulatory treatment. Certain provisions of the accounting guidance for income taxes allow regulated enterprises to recognize deferred taxes as regulatory tax assets or tax liabilities if it is probable that such amounts will be recovered from, or returned to, customers in future rates.
We report interest and penalties related to uncertain tax positions as current income tax expense.
Accounting for Contingencies
Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 12 for a discussion of contingencies.
Cash and Cash Equivalents
For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents.
Restricted Cash
The terms of certain agreements require the restriction of cash for specific purposes. As of December 31, 2010, $1.135 billion of cash was restricted to support letters of credit. See Notes 11 and 24 for more details regarding restricted cash.
Property, Plant and Equipment
As a result of purchase accounting, carrying amounts of property, plant and equipment related to unregulated businesses were adjusted to estimated fair values at the Merger date. Subsequent additions have been recorded at cost. Oncor’s properties are reported at original cost, which is considered to be fair value due to the cost-based regulated recovery and returns associated with those assets. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead, including payroll-related costs.
Depreciation of our property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation expense for unregulated properties is calculated on a component asset-by-asset basis. As is common in the industry for regulated operations, Oncor’s depreciation expense is calculated using composite depreciation rates that reflect blended estimates of the lives of major asset groups. Estimated depreciable lives are based on management’s estimates of the assets’ economic useful lives or, in the case of Oncor, as set by PUCT orders. See Note 24.
Capitalized Interest
Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization of interest cost. See Note 24.
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Inventories
Inventories are reported at the lower of cost (on a weighted average basis) or market unless expected to be used in the generation of electricity. Also see discussion immediately below regarding environmental allowances and credits.
Environmental Allowances and Credits
We account for all environmental allowances and credits as identifiable intangible assets with finite lives that are subject to amortization. The recorded values of these intangible assets were originally established reflecting fair value determinations as of the date of the Merger under purchase accounting. Amortization expense associated with these intangible assets is recognized on a unit of production basis as the allowances or credits are consumed in generation operations. The environmental allowances and credits are assessed for impairment when conditions or events occur that could affect the carrying value of the assets. See Note 4 for details of impairment amounts recorded in 2008.
Regulatory Assets and Liabilities
The financial statements of our regulated electricity delivery operations reflect regulatory assets and liabilities under cost-based rate regulation in accordance with accounting standards related to the effect of certain types of regulation. Regulatory decisions can have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 24 for details of the regulatory assets and liabilities.
Investments
Investments in unconsolidated subsidiaries, which are 50% or less owned and/or do not meet accounting standards criteria for consolidation, are accounted for under the equity method. See Note 2 for discussion of equity method investments and Note 3 for discussion of VIEs.
Investments in a nuclear decommissioning trust fund are carried at current market value in the balance sheet. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current market value. See Note 18 for discussion of these and other investments.
Noncontrolling Interests
See Note 14 for discussion of accounting for noncontrolling interests in subsidiaries.
Changes in Accounting Standards
As of January 1, 2010, we adopted new FASB guidance that requires reconsideration of consolidation conclusions for all VIEs and other entities with which we are involved. See Note 3 for discussion of our evaluation of VIEs and the resulting deconsolidation of Oncor Holdings and its subsidiaries that resulted in our investment in Oncor Holdings and its subsidiaries being prospectively reported as an equity method investment. There were no other material effects on our financial statements as a result of the adoption of this new guidance.
As of January 1, 2010, we adopted new FASB guidance regarding accounting for transfers of financial assets that eliminates the concept of a qualifying special purpose entity, changes the requirements for derecognizing financial assets and requires additional disclosures. Accordingly, the trade accounts receivable amounts under the accounts receivable securitization program discussed in Note 10 are now reported as pledged balances, and the related funding amounts are reported as short-term borrowings. Prior to January 1, 2010, the activity was accounted for as a sale of accounts receivable in accordance with previous accounting standards, which resulted in the funding being recorded as a reduction of accounts receivable. This new guidance does not impact the covenant-related ratio calculations in our debt agreements.
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| 2. | EQUITY METHOD INVESTMENTS |
Investments in unconsolidated subsidiaries consisted of the following:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
Investment in Oncor Holdings (100% owned) (a) | $ | 5,544 | $ | — | ||||
Investment in natural gas gathering pipeline business (b) | — | 44 | ||||||
Total investments in unconsolidated subsidiaries | $ | 5,544 | $ | 44 | ||||
| ||||||||
| (a) | Oncor Holdings owns approximately 80% of the membership interests of Oncor and was deconsolidated effective January 1, 2010 (see Notes 1 and 3). |
| (b) | A controlling interest in this previously consolidated subsidiary was sold in 2009, and the remaining interests were sold in June 2010. |
Oncor Holdings
Effective January 1, 2010, we account for our investment in Oncor Holdings under the equity method (see Note 3). Prior to this date, Oncor Holdings was a consolidated subsidiary. Oncor Holdings owns approximately 80% of Oncor (an SEC registrant), which is engaged in regulated electricity transmission and distribution operations in Texas. Distribution revenues from TCEH represented 36%, 38% and 39% of total revenues for Oncor Holdings for the years ended December 31, 2010, 2009 and 2008, respectively. Condensed statements of consolidated income of Oncor Holdings for the years ended December 31, 2010, 2009 and 2008 are presented below:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Operating revenues | $ | 2,914 | $ | 2,690 | $ | 2,580 | ||||||
Operation and maintenance expenses | (1,009 | ) | (962 | ) | (852 | ) | ||||||
Write off of regulatory assets | — | (25 | ) | — | ||||||||
Depreciation and amortization | (673 | ) | (557 | ) | (492 | ) | ||||||
Taxes other than income taxes | (384 | ) | (385 | ) | (391 | ) | ||||||
Impairment of goodwill | — | — | (860 | ) | ||||||||
Other income | 36 | 49 | 45 | |||||||||
Other deductions | (8 | ) | (14 | ) | (25 | ) | ||||||
Interest income | 38 | 43 | 45 | |||||||||
Interest expense and related charges | (347 | ) | (346 | ) | (316 | ) | ||||||
Income (loss) before income taxes | 567 | 493 | (266 | ) | ||||||||
Income tax expense | (220 | ) | (173 | ) | (217 | ) | ||||||
Net income (loss) | 347 | 320 | (483 | ) | ||||||||
Net (income) loss attributable to noncontrolling interests | (70 | ) | (64 | ) | 160 | |||||||
Net income (loss) attributable to Oncor Holdings | $ | 277 | $ | 256 | $ | (323 | ) | |||||
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Assets and liabilities of Oncor Holdings as of December 31, 2010 and 2009 are presented below:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (millions of dollars) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 33 | $ | 29 | ||||
Restricted cash | 53 | 47 | ||||||
Trade accounts receivable — net | 254 | 243 | ||||||
Trade accounts and other receivables from affiliates | 182 | 188 | ||||||
Income taxes receivable from EFH Corp. | 72 | — | ||||||
Inventories | 96 | 92 | ||||||
Accumulated deferred income taxes | 10 | 10 | ||||||
Prepayments | 75 | 76 | ||||||
Other current assets | 5 | 8 | ||||||
Total current assets | 780 | 693 | ||||||
Restricted cash | 16 | 14 | ||||||
Other investments | 78 | 72 | ||||||
Property, plant and equipment — net | 9,676 | 9,174 | ||||||
Goodwill | 4,064 | 4,064 | ||||||
Note receivable due from TCEH | 178 | 217 | ||||||
Regulatory assets — net | 1,782 | 1,959 | ||||||
Other noncurrent assets | 264 | 51 | ||||||
Total assets | $ | 16,838 | $ | 16,244 | ||||
LIABILITIES | ||||||||
Current liabilities: | ||||||||
Short-term borrowings | $ | 377 | $ | 616 | ||||
Long-term debt due currently | 113 | 108 | ||||||
Trade accounts payable — nonaffiliates | 125 | 129 | ||||||
Income taxes payable to EFH Corp. | — | 5 | ||||||
Accrued taxes other than income | 133 | 137 | ||||||
Accrued interest | 108 | 104 | ||||||
Other current liabilities | 109 | 106 | ||||||
Total current liabilities | 965 | 1,205 | ||||||
Accumulated deferred income taxes | 1,516 | 1,369 | ||||||
Investment tax credits | 32 | 37 | ||||||
Long-term debt, less amounts due currently | 5,333 | 4,996 | ||||||
Other noncurrent liabilities and deferred credits | 1,996 | 1,879 | ||||||
Total liabilities | $ | 9,842 | $ | 9,486 | ||||
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Oncor Debt Issuances and Exchanges
In September 2010, Oncor issued $475 million aggregate principal amount of 5.250% senior secured notes maturing in September 2040. Oncor used the net proceeds of approximately $465 million from the sale of the notes to repay borrowings under its revolving credit facility, including loans under the revolving credit facility made by certain of the initial purchasers of the notes or their affiliates, and for general corporate purposes. The notes are secured by a first priority lien on Oncor’s assets equally and ratably with all of Oncor’s other secured indebtedness.
In October 2010, Oncor issued approximately $324.4 million aggregate principal amount of 5.000% senior secured notes due 2017 and approximately $126.3 million aggregate principal amount of 5.750% senior secured notes due 2020 in exchange for an equivalent principal amount of its outstanding 6.375% senior secured notes due 2012 and 5.950% senior secured notes due 2013, respectively. Oncor did not receive any cash proceeds from the exchange.
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| 3. | CONSOLIDATION OF 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. We adopted amended accounting standards on January 1, 2010 that require consolidation of a VIE if we have (a) the power to direct the significant activities of the VIE and (b) the right or obligation to absorb profit and loss from the VIE (primary beneficiary). The previous standards did not require power to direct significant activities of the VIE in order to consolidate. As discussed below, our balance sheet includes assets and liabilities of VIEs that meet the consolidation standards and also reflects the deconsolidation of Oncor Holdings, which holds an approximate 80% interest in Oncor.
Our VIEs consist of equity investees. In determining the appropriateness of consolidation of a VIE, we evaluate its purpose, governance structure, decision making processes and risks that are passed on to its interest holders. We also examine the nature of any related party relationships among the interest holders of the VIE and the nature of any special rights granted to the interest holders of the VIE.
Consolidated VIEs
No additional VIEs were consolidated as a result of the new accounting standards. See discussion in Note 10 regarding the VIE related to our accounts receivable securitization program that continues to be consolidated under the amended accounting standards.
We also continue to consolidate Comanche Peak Nuclear Power Company LLC (CPNPC), which was formed by subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) for the purpose of developing two new nuclear generation units at our existing Comanche Peak nuclear-fueled generation facility using MHI’s US-Advanced Pressurized Water Reactor technology and to obtain a combined operating license from the NRC. CPNPC is currently financed through capital contributions from the subsidiaries of TCEH and MHI that hold 88% and 12% of CPNPC’s equity interests, respectively (see Note 14).
The carrying amounts and classifications of the assets and liabilities related to our consolidated VIEs as of December 31, 2010 are as follows:
Assets: | Liabilities: | |||||||||
Cash and cash equivalents | $ | 9 | Short-term borrowings (a) | $ | 96 | |||||
Accounts receivable (a) | 612 | Trade accounts payable | 3 | |||||||
Property, plant and equipment | 112 | Other current liabilities | 1 | |||||||
Other assets, including $2 of current assets | 8 | |||||||||
Total assets | $ | 741 | Total liabilities | $ | 100 | |||||
| (a) | As a result of the January 1, 2010 adoption of new accounting guidance related to transfers of financial assets, the balance sheet as of December 31, 2010 reflects $612 million of pledged accounts receivable and $96 million of short-term borrowings (see Note 10). |
The assets of our consolidated VIEs can only be used to settle the obligations of the VIE, and the creditors of our consolidated VIEs do not have recourse to our general credit.
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Non-Consolidated VIEs
The adoption of the amended accounting standards resulted in the deconsolidation of Oncor Holdings, which holds an approximate 80% interest in Oncor, and the reporting of our investment in Oncor Holdings under the equity method on a prospective basis.
In reaching the conclusion to deconsolidate, we conducted an extensive analysis of Oncor Holdings’ underlying governing documents and management structure. Oncor Holdings’ unique governance structure was adopted in conjunction with the Merger, when the Sponsor Group, EFH Corp. and Oncor agreed to implement structural and operational measures to “ring-fence” (the Ring-Fencing Measures) Oncor Holdings and Oncor as discussed in Note 1. The Ring-Fencing Measures were designed to prevent, among other things, (i) increased borrowing costs at Oncor due to the attribution to Oncor of debt from any of our other subsidiaries, (ii) the activities of our unregulated operations following the Merger resulting in the deterioration of Oncor’s business, financial condition and/or investment in infrastructure, and (iii) Oncor becoming substantively consolidated into a bankruptcy proceeding involving any member of the Texas Holdings Group. The Ring-Fencing Measures effectively separated the daily operational and management control of Oncor Holdings and Oncor from EFH Corp. and its other subsidiaries. By implementing the Ring-Fencing Measures, Oncor maintained its investment grade credit rating following the Merger, and we reaffirmed Oncor’s independence from our unregulated businesses to the PUCT.
We determined the most significant activities affecting the economic performance of Oncor Holdings (and Oncor) are the operation, maintenance and growth of Oncor’s electric transmission and distribution assets and the preservation of its investment grade credit profile. The boards of directors of Oncor Holdings and Oncor have ultimate responsibility for the management of the day-to-day operations of their respective businesses, including the approval of Oncor’s capital expenditure and operating budgets and the timing and prosecution of Oncor’s rate cases. While both boards include members appointed by EFH Corp., a majority of the board members are independent in accordance with rules established by the New York Stock Exchange, and therefore, we concluded for purposes of applying the amended accounting standards that EFH Corp. does not have the power to control the activities deemed most significant to Oncor Holdings’ (and Oncor’s) economic performance.
In assessing EFH Corp.’s ability to exercise control over Oncor Holdings and Oncor, we considered whether it could take actions to circumvent the purpose and intent of the Ring-Fencing Measures (including changing the composition of Oncor Holdings’ or Oncor’s board) in order to gain control over the day-to-day operations of either Oncor Holdings or Oncor. We also considered whether (i) EFH Corp. has the unilateral power to dissolve, liquidate or force into bankruptcy either Oncor Holdings or Oncor, (ii) EFH Corp. could unilaterally amend the Ring-Fencing Measures contained in the underlying governing documents of Oncor Holdings or Oncor, and (iii) EFH Corp. could control Oncor’s ability to pay distributions and thereby enhance its own cash flow. We concluded that, in each case, no such opportunity exists.
We account for our investment in Oncor Holdings under the equity method, as opposed to the cost method, because we have the ability to exercise significant influence (as defined by US GAAP) over its activities. Our maximum exposure to loss from our variable interests in VIEs does not exceed our carrying value. See Note 2 for additional information about equity method investments including condensed income statement and balance sheet data for Oncor Holdings.
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| 4. | GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS |
Goodwill
The following table provides the goodwill balances as of December 31, 2010 and the changes in such balances for the year ended December 31, 2010. With the deconsolidation of Oncor (including its $4.064 billion goodwill balance) effective January 1, 2010, the amounts below relate only to our competitive business. None of the goodwill is being deducted for tax purposes.
Goodwill before impairment charges | $ | 18,342 | ||
Accumulated impairment charges through 2009 (a) | (8,090 | ) | ||
Balance as of January 1, 2010 | 10,252 | |||
Additional impairment charge in 2010 | (4,100 | ) | ||
Balance as of December 31, 2010 (b) | $ | 6,152 | ||
| ||||
| (a) | Includes $90 million in 2009 ($20 million of which was recorded in Corporate and Other results) and $8.0 billion in 2008. |
| (b) | Net of accumulated impairment charges totaling $12.190 billion. |
Goodwill and Trade Name Intangible Asset Impairments
In the third quarter 2010, we recorded a $4.1 billion noncash goodwill impairment charge related to the Competitive Electric segment. The impairment testing and resulting charge was driven by the sustained decline in forward natural gas prices and reflected the estimated effect of lower wholesale power prices on the enterprise value of the business as indicated by our cash flow projections and declines in market values of securities of comparable companies.
The calculation of the goodwill impairment involved the following steps: first, we estimated the debt-free enterprise value of the business as of July 31, 2010 taking into account future estimated cash flows and current securities values of comparable companies; second, we estimated the fair values of the individual operating assets and liabilities of the business at that date; third, we calculated “implied” goodwill as the excess of the estimated enterprise value over the estimated value of the net operating assets; and finally, we compared the implied goodwill amount to the carrying value of goodwill and recorded an impairment charge for the amount the carrying value of goodwill exceeded implied goodwill.
The annual impairment testing performed as of December 1, 2010 for goodwill and intangible assets with indefinite useful lives resulted in no additional impairment beyond the charge recorded in the third quarter 2010 discussed immediately above. The annual goodwill test determined that the Competitive Electric segment carrying value exceeded its estimated fair value (enterprise value) by approximately 11%. The estimated enterprise value as of December 1, 2010 did not change materially from the estimate at July 31, 2010. Additional testing was performed to ascertain that the estimated implied goodwill amount as of December 1 had not declined further from the amount estimated at July 31.
In the first quarter 2009, we completed the fair value calculations supporting an initial $8.860 billion goodwill impairment charge that was recorded in the fourth quarter 2008 and consisted of an estimated impairment of $8.0 billion related to the Competitive Electric segment and $860 million related to the Regulated Delivery segment. A $90 million increase in the charge, largely related to the Competitive Electric segment, was recorded in the first quarter 2009. The impairment charge primarily reflected the dislocation in the capital markets during the fourth quarter 2008 that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies. The calculation involved the same steps as those discussed above for the 2010 impairment. The total $8.950 billion charge was the first goodwill impairment recorded subsequent to the Merger date.
Also in the fourth quarter 2008, we recorded a trade name intangible asset impairment charge totaling $481 million ($310 million after-tax). The impairment primarily arose from the increase in the discount rate used in estimating fair value as discussed above.
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Although the annual impairment test date for goodwill and intangible assets with indefinite lives set by management at that time was October 1, management determined that in consideration of the continuing deterioration of securities values during the fourth quarter 2008, an impairment testing trigger occurred subsequent to that test date; consequently, the impairment charges were based on estimated fair values as of December 31, 2008.
The impairment determinations involved significant assumptions and judgments. The calculations supporting the estimates of the enterprise value of our businesses and the fair values of their operating assets and liabilities utilized models that take into consideration multiple inputs, including commodity prices, discount rates, debt yields, securities prices of comparable companies and other inputs, assumptions regarding each of which could have a significant effect on valuations. The fair value measurements resulting from these models are classified as non-recurring Level 3 measurements consistent with accounting standards related to the determination of fair value (see Note 15). Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.
Identifiable Intangible Assets
Identifiable intangible assets reported in the balance sheet are comprised of the following:
| As of December 31, 2010 (a) | As of December 31, 2009 | |||||||||||||||||||||||
Gross | Accumulated | Gross | Accumulated | |||||||||||||||||||||
Identifiable Intangible Asset | Amount | Amortization | Net | Amount | Amortization | Net | ||||||||||||||||||
Retail customer relationship | $ | 463 | $ | 293 | $ | 170 | $ | 463 | $ | 215 | $ | 248 | ||||||||||||
Favorable purchase and sales contracts | 548 | 257 | 291 | 700 | 374 | 326 | ||||||||||||||||||
Capitalized in-service software | 278 | 97 | 181 | 490 | 167 | 323 | ||||||||||||||||||
Environmental allowances and credits | 986 | 304 | 682 | 992 | 212 | 780 | ||||||||||||||||||
Land easements | — | — | — | 188 | 72 | 116 | ||||||||||||||||||
Mining development costs | 47 | 17 | 30 | 32 | 5 | 27 | ||||||||||||||||||
Total intangible assets subject to amortization | $ | 2,322 | $ | 968 | 1,354 | $ | 2,865 | $ | 1,045 | 1,820 | ||||||||||||||
Trade name (not subject to amortization) | 955 | 955 | ||||||||||||||||||||||
Mineral interests (not currently subject to amortization) | 91 | 101 | ||||||||||||||||||||||
Total intangible assets | $ | 2,400 | $ | 2,876 | ||||||||||||||||||||
| (a) | See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010. |
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Amortization expense related to intangible assets (including income statement line item) consisted of:
Useful lives as | Year Ended December 31, | |||||||||||||||||||
Identifiable Intangible Asset | Income Statement Line | Segment | years) | 2010 | 2009 | 2008 | ||||||||||||||
Retail customer relationship | Depreciation and amortization | Competitive Electric | 7 | $ | 78 | $ | 85 | $ | 51 | |||||||||||
Favorable purchase and sales contracts | Operating revenues/fuel, purchased power costs and delivery fees | Competitive Electric | 12 | 35 | 125 | 168 | ||||||||||||||
Capitalized in-service software | Depreciation and amortization | All (a) | 5 | 35 | 53 | 44 | ||||||||||||||
Environmental allowances and credits | Fuel, purchased power costs and delivery fees | Competitive Electric | 27 | 92 | 91 | 102 | ||||||||||||||
Land easements | Depreciation and amortization | Regulated Delivery (a) | N/A | — | 3 | 3 | ||||||||||||||
Mining development costs | Depreciation and amortization | Competitive Electric | 3 | 11 | 3 | 1 | ||||||||||||||
Total amortization expense | $ | 251 | $ | 360 | $ | 369 | ||||||||||||||
| (a) | See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010. |
Separately identifiable and previously unrecognized intangible assets acquired and recorded as part of purchase accounting for the Merger are described as follows:
| • | Retail Customer Relationship – Retail customer relationship intangible asset represents the estimated fair value of the non-contracted customer base and is being amortized using an accelerated method based on customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life. |
| • | Favorable Purchase and Sales Contracts – Favorable purchase and sales contracts intangible asset primarily represents the above market value, based on observable prices or estimates, of commodity contracts for which: (i) we have made the “normal” purchase or sale election allowed by accounting standards related to derivative instruments and hedging transactions or (ii) the contracts did not meet the definition of a derivative. The amortization periods of these intangible assets are based on the terms of the contracts. Unfavorable purchase and sales contracts are recorded as other noncurrent liabilities and deferred credits (see Note 24). |
| • | Trade name – The trade name intangible asset represents the estimated fair value of the TXU Energy trade name, and was determined to be an indefinite-lived asset not subject to amortization. This intangible asset is evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other intangible assets. See above for discussion of an impairment charge recorded in 2008. |
| • | Environmental Allowances and Credits –This intangible asset represents the fair value, based on observable prices or estimates, of environmental credits, substantially all of which were expected to be used in our power generation activities. These credits are amortized utilizing a units-of-production method. |
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Impairment of Environmental Allowances and Credits Intangible Assets
In March 2005, the EPA issued regulations called the Clean Air Interstate Rule (CAIR) for 28 states, including Texas, where our generation facilities are located. CAIR requires reductions of SO2 and NOx emissions from power generation facilities in these states. The SO2 reductions were beyond the reductions required under the Clean Air Act’s existing acid rain cap-and-trade program (the Acid Rain Program). CAIR also established a new regional cap-and-trade program for NOx emissions reductions.
In July 2008, the US Court of Appeals for the D.C. Circuit (the D.C. Circuit Court) invalidated CAIR. The D.C. Circuit Court did not overturn the existing cap-and-trade program for SO2 reductions under the Acid Rain Program.
Based on the D.C. Circuit Court’s ruling, we recorded a noncash impairment charge to earnings in 2008. We impaired NOx allowances in the amount of $401 million (before deferred income tax benefit). As a result of the D.C. Circuit Court’s decision, NOx allowances would no longer be needed, and thus there would not be an actively traded market for such allowances. Consequently, our NOx allowances would likely have very little value absent reversal of the D.C. Circuit Court’s decision or promulgation of new rules by the EPA. In addition, we impaired SO2 allowances in the amount of $100 million (before deferred income tax benefit). While the D.C. Circuit Court did not invalidate the Acid Rain Program, we would have more SO2 allowances than we would need to comply with the Acid Rain Program. While there continued to be a market for SO2 allowances, the D.C. Circuit Court’s decision resulted in a material decrease in the market price of SO2 allowances.
The impairment amounts recorded in 2008 were reported in other deductions and reflected in the results of the Competitive Electric segment.
In December 2008, in response to an EPA petition, the D.C. Circuit Court reversed, in part, its previous ruling. Such reversal confirmed CAIR is not valid, but allowed it to remain in place while the EPA revises CAIR to correct the previously identified shortcomings. In July 2010, the EPA released a proposed rule called the Clean Air Transport Rule (CATR). The CATR, as proposed, would replace CAIR in 2012. We cannot predict the impact of a final rule on our business, results of operations and financial condition.
Estimated Amortization of Intangible Assets–The estimated aggregate amortization expense of intangible assets for each of the next five fiscal years is as follows:
Year | Amortization Expense | |||
2011 | $ | 198 | ||
2012 | 154 | |||
2013 | 132 | |||
2014 | 116 | |||
2015 | 98 | |||
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| 5. | IMPAIRMENT OF NATURAL GAS-FUELED GENERATION FACILITIES |
In 2008, we performed an evaluation of our natural gas-fueled generation facilities for impairment. The impairment test was triggered by a determination that it was more likely than not that certain generation units would be retired or mothballed (idled) earlier than previously expected. The natural gas-fueled generation units are generally operated to meet peak demands for electricity and all such facilities are tested for impairment as an asset group. As a result of the evaluation, it was determined that an impairment existed, and a charge of $229 million ($147 million after-tax) was recorded to write down the assets to fair value of approximately $28 million, which was determined based on discounted estimated future cash flows. The impairment was reported in other deductions in the Competitive Electric segment.
| 6. | MERGER-RELATED STIPULATION APPROVED BY THE PUCT |
In 2008, the PUCT issued a final order approving a stipulation to resolve all outstanding issues in the PUCT review related to the Merger. The terms of the stipulation were agreed to by Oncor and Texas Holdings as well as major interested parties, conditioned on completion of the Merger. The order has been appealed with respect to certain elements, none of which are expected to affect the following major provisions of the stipulation:
| • | Oncor provided a one-time $72 million refund to its REP customers in the September 2008 billing cycle. The refund was in the form of a credit on distribution fee billings. The liability for the refund was recorded as part of purchase accounting. |
| • | Consistent with a rate settlement with certain cities in 2006, Oncor filed a system-wide rate case in June 2008 based on a test-year ended December 31, 2007. In August 2009, the PUCT issued a final order on this rate case. See Note 24. |
| • | Oncor agreed not to request recovery of approximately $56 million of regulatory assets related to self-insurance reserve costs and 2002 restructuring expenses. These regulatory assets were eliminated as part of purchase accounting. |
| • | The cash distributions paid by Oncor to its members will be limited 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) for the period beginning October 11, 2007 and ending December 31, 2012, and are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity (see Note 13). |
| • | Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. |
| • | Oncor committed to an additional $100 million in spending over the five-year period ending December 31, 2012 on demand-side management or other energy efficiency initiatives. These additional expenditures will not be recoverable in rates, and this amount was recorded as a regulatory liability as part of purchase accounting and consistent with accounting standards related to the effect of certain types of regulation. |
| • | If Oncor’s credit rating is below investment grade with two or more rating agencies, TCEH will post a letter of credit in an amount of $170 million to secure TXU Energy’s payment obligations to Oncor. |
| • | Oncor agreed not to request recovery of the $4.9 billion of goodwill resulting from purchase accounting or any future impairment of the goodwill in its rates. |
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| 7. | ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES |
Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable.
We file income tax returns in US federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of our income tax returns for the years ending prior to January 1, 2003 are complete, but the tax years 1997 to 2002 remain in appeals with the IRS. An IRS audit of tax years 2003 to 2006 is in progress and is expected to be completed in 2011. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginning after 2002.
In 2008, we participated in negotiations with the IRS regarding the 2002 worthlessness loss associated with our discontinued Europe business, and we reduced the liability for uncertain tax positions in accordance with accounting guidance. The reduction in the liability of approximately $375 million was largely offset by a reduction of deferred tax assets related to alternative minimum tax.
In 2010, we again engaged in negotiations with the IRS regarding this worthlessness loss as well as other matters. Accordingly, we have adjusted the liability for uncertain tax positions to reflect the most likely settlement of the issues. The adjustment resulted in a net reduction of the liability for uncertain tax positions totaling $162 million. This reduction consisted of a $225 million reversal of accrued interest ($146 million after tax), reported as a reduction of income tax expense, principally related to the discontinued Europe business, partially offset by $63 million in adjustments related to several other positions that have been accounted for as reclassifications to net deferred tax liabilities. The conclusion of all issues contested from the 1997 through 2002 audit, including IRS Joint Committee review, is expected to occur before the end of 2012. Upon such conclusion, we expect to further reduce the liability for uncertain tax positions by approximately $700 million with an offsetting decrease in deferred tax assets that arose largely from previous payments of alternative minimum taxes. No cash income tax liability is expected related to the conclusion of the 1997 through 2002 audit.
We classify interest and penalties related to uncertain tax positions as current income tax expense. Amounts recorded related to interest and penalties totaled a benefit of $115 million in 2010, and expenses of $42 million in 2009 and $88 million in 2008, including $29 million recorded as goodwill (all amounts after tax).
Noncurrent liabilities included a total of $164 million and $361 million in accrued interest as of December 31, 2010 and 2009, respectively. Oncor Holdings, which had $20 million in noncurrent liabilities related to accrued interest, was deconsolidated as of January 1, 2010 as discussed in Note 2. The federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferred income taxes.
The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in the consolidated balance sheet, during the years ended December 31, 2010, 2009 and 2008:
| 2010 | 2009 | 2008 | ||||||||||
Balance as of January 1, excluding interest and penalties (a) | $ | 1,566 | $ | 1,583 | $ | 1,834 | ||||||
Additions based on tax positions related to prior years | 312 | 71 | 124 | |||||||||
Reductions based on tax positions related to prior years | (308 | ) | (82 | ) | (451 | ) | ||||||
Additions based on tax positions related to the current year | 72 | 66 | 33 | |||||||||
Settlements with taxing authorities | — | — | 43 | |||||||||
Balance as of December 31, excluding interest and penalties | $ | 1,642 | $ | 1,638 | $ | 1,583 | ||||||
| (a) | 2010 reflects the deconsolidation of Oncor Holdings, which had a balance of $72 million, as of January 1, 2010. |
Of the balance as of December 31, 2010, $1.442 billion represents tax positions for which the uncertainty relates to the timing of recognition in tax returns. The disallowance of such positions would not affect the effective tax rate, but could accelerate the payment of cash to the taxing authority to an earlier period.
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With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), should we sustain such positions on income tax returns previously filed, tax liabilities recorded would be reduced by $200 million, and accrued interest would be reversed resulting in a $28 million after-tax benefit, resulting in increased net income and a favorable impact on the effective tax rate.
Other than the items discussed above, we do not expect the total amount of liabilities recorded related to uncertain tax positions will significantly increase or decrease within the next 12 months.
| 8. | INCOME TAXES |
The components of our income tax expense (benefit) applicable to continuing operations are as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Current: | ||||||||||||
US Federal | $ | (256 | ) | $ | 64 | $ | (46 | ) | ||||
State | 41 | 51 | 52 | |||||||||
Total | (215 | ) | 115 | 6 | ||||||||
Deferred: | ||||||||||||
US Federal | 590 | 256 | (482 | ) | ||||||||
State | 14 | 1 | 10 | |||||||||
Total | 604 | 257 | (472 | ) | ||||||||
Amortization of investment tax credits | — | (5 | ) | (5 | ) | |||||||
Total | $ | 389 | $ | 367 | $ | (471 | ) | |||||
Reconciliation of income taxes computed at the US federal statutory rate to income tax expense:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Income (loss) before income taxes | $ | (2,700 | ) | $ | 775 | $ | (10,469 | ) | ||||
Income taxes at the US federal statutory rate of 35% | $ | (945 | ) | $ | 271 | $ | (3,664 | ) | ||||
Nondeductible goodwill impairment | 1,435 | 32 | 3,101 | |||||||||
Lignite depletion allowance | (21 | ) | (18 | ) | (29 | ) | ||||||
Amortization of investment tax credits, net of tax | — | (5 | ) | (5 | ) | |||||||
Amortization (under regulatory accounting) of statutory rate changes | — | 5 | 2 | |||||||||
Medicare subsidy — retiree benefits | — | (7 | ) | (6 | ) | |||||||
Nondeductible interest expense | 11 | 13 | 11 | |||||||||
Nondeductible losses (earnings) on benefit plans | — | (1 | ) | 9 | ||||||||
Texas margin tax, net of federal benefit | 34 | 30 | 39 | |||||||||
Interest accrued for uncertain tax positions, net of tax | (115 | ) | 42 | 59 | ||||||||
Deferred tax charge for effect of health care legislation | 8 | — | — | |||||||||
Reversal of previously disallowed interest resulting from debt exchanges | (21 | ) | — | — | ||||||||
Other, including audit settlements | 3 | 5 | 12 | |||||||||
Income tax expense (benefit) | $ | 389 | $ | 367 | $ | (471 | ) | |||||
Effective tax rate | (14.4 | )% | 47.4 | % | 4.5 | % | ||||||
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Deferred Income Tax Balances
Deferred income taxes provided for temporary differences based on tax laws in effect as of December 31, 2010 and 2009 balance sheet dates are as follows:
| December 31, | ||||||||||||||||||||||||
| 2010 (a) | 2009 | |||||||||||||||||||||||
| Total | Current | Noncurrent | Total | Current | Noncurrent | |||||||||||||||||||
Deferred Income Tax Assets | ||||||||||||||||||||||||
Alternative minimum tax credit carryforwards | $ | 406 | $ | — | $ | 406 | $ | 438 | $ | — | $ | 438 | ||||||||||||
Employee benefit liabilities | 216 | 25 | 191 | 206 | 22 | 184 | ||||||||||||||||||
Net operating loss (NOL) carryforwards | 833 | — | 833 | 422 | — | 422 | ||||||||||||||||||
Unfavorable purchase and sales contracts | 240 | — | 240 | 249 | — | 249 | ||||||||||||||||||
Accrued interest | 157 | — | 157 | 211 | — | 211 | ||||||||||||||||||
Other | 317 | 2 | 315 | 351 | 13 | 338 | ||||||||||||||||||
Total | 2,169 | 27 | 2,142 | 1,877 | 35 | 1,842 | ||||||||||||||||||
Deferred Income Tax Liabilities | ||||||||||||||||||||||||
Property, plant and equipment | 4,321 | — | 4,321 | 4,141 | — | 4,141 | ||||||||||||||||||
Basis difference in Oncor partnership | — | — | — | 1,369 | — | 1,369 | ||||||||||||||||||
Commodity contracts and interest rate swaps | 1,692 | 31 | 1,661 | 1,325 | 30 | 1,295 | ||||||||||||||||||
Identifiable intangible assets | 846 | — | 846 | 921 | — | 921 | ||||||||||||||||||
Debt fair value discounts | 126 | — | 126 | 184 | — | 184 | ||||||||||||||||||
Debt extinguishment gains | 503 | — | 503 | 35 | — | 35 | ||||||||||||||||||
Other | 42 | 7 | 35 | 28 | — | 28 | ||||||||||||||||||
Total | 7,530 | 38 | 7,492 | 8,003 | 30 | 7,973 | ||||||||||||||||||
Net Deferred Income Tax (Asset) Liability | $ | 5,361 | $ | 11 | �� | $ | 5,350 | $ | 6,126 | $ | (5 | ) | $ | 6,131 | ||||||||||
| (a) | See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010. |
As of December 31, 2010 we had $406 million of alternative minimum tax credit carryforwards (AMT) available to offset future tax payments. The AMT credit carryforwards have no expiration date. As of December 31, 2010, we had net operating loss (NOL) carryforwards for federal income tax purposes of $2.4 billion that expire between 2028 and 2031. The NOL carryforwards can be used to offset future taxable income. We expect to utilize all of our NOL carryforwards prior to their expiration dates.
The component of deferred income tax liabilities referred to as “basis difference in Oncor partnership” arose as a result of the sale of noncontrolling interests in Oncor (see Note 14) at which time Oncor became a partnership for US federal income tax purposes. The amount of this basis difference at the date of the transaction represented our interest (approximately 80%) in the net deferred tax liabilities related to Oncor’s individual operating assets and liabilities. The remaining net deferred tax liabilities associated with Oncor ($321 million as of December 31, 2009) that were attributable to the noncontrolling interests were reclassified as other noncurrent liabilities and deconsolidated with Oncor Holdings in 2010 as discussed in Notes 1 and 3 (see Note 24).
The income tax effects of the components included in accumulated other comprehensive income as of December 31, 2010 and 2009 totaled a net deferred tax asset of $141 million and $165 million, respectively.
See Note 7 for discussion regarding accounting for uncertain tax positions.
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Effect of Health Care Legislation — The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act enacted in March 2010 reduces, effective in 2013, the amount of OPEB costs deductible for federal income tax purposes by the amount of the Medicare Part D subsidy we receive. Under income tax accounting rules, deferred tax assets related to accrued OPEB liabilities must be reduced immediately for the future effect of the legislation. Accordingly, in the first quarter 2010, EFH Corp.’s and Oncor’s deferred tax assets were reduced by $50 million. Of this amount, $8 million was recorded as a charge to income tax expense and $42 million was recorded in receivables from unconsolidated subsidiary, reflecting a regulatory asset recorded by Oncor (before gross-up for liability in lieu of deferred income taxes) as the additional income taxes are expected to be recoverable in Oncor’s future rates.
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| 9. | OTHER INCOME AND DEDUCTIONS |
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Other income: | ||||||||||||
Debt extinguishment gains (Note 11) (a) | $ | 1,814 | $ | 87 | $ | — | ||||||
Gain on termination of long-term power sales contract (b) (c) | 116 | — | — | |||||||||
Gain on sale of land/water rights (c) | 44 | — | — | |||||||||
Gain on sale of interest in natural gas gathering pipeline business (c) | 37 | — | — | |||||||||
Office space rental income (a) | 12 | — | — | |||||||||
Insurance/litigation settlements (c) (d) | 6 | — | 21 | |||||||||
Sales tax refund | 5 | 5 | — | |||||||||
Mineral rights royalty income (c) | 1 | 6 | 4 | |||||||||
Reversal of reserves recorded in purchase accounting (e) | — | 44 | — | |||||||||
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting (Note 24) (f) | — | 39 | 44 | |||||||||
Fee received related to interest rate swap/commodity hedge derivative agreement (Note 17) (c) | — | 6 | — | |||||||||
Other | 16 | 17 | 11 | |||||||||
Total other income | $ | 2,051 | $ | 204 | $ | 80 | ||||||
Other deductions: | ||||||||||||
Impairment of trade name intangible asset (Note 4) (c) | $ | — | $ | — | $ | 481 | ||||||
Impairment of emission allowances intangible assets (Note 4) (c) | — | — | 501 | |||||||||
Charge for impairment of natural gas-fueled generation facilities (Note 5) (c) | — | — | 229 | |||||||||
Impairment of land (c) | — | 34 | — | |||||||||
Charge related to Lehman bankruptcy (g) | — | — | 26 | |||||||||
Write-off of regulatory assets (Note 24) (f) | — | 25 | — | |||||||||
Ongoing pension and OPEB expense related to discontinued businesses (a) | 7 | — | — | |||||||||
Professional fees incurred related to the Merger (h) | 5 | — | 14 | |||||||||
Net charges related to cancelled development of generation facilities (c) | 3 | 6 | 12 | |||||||||
Severance charges | 3 | 7 | — | |||||||||
Costs related to 2006 cities rate settlement (f) | — | 2 | 13 | |||||||||
Litigation/regulatory settlements | — | 3 | 10 | |||||||||
Other | 13 | 20 | 15 | |||||||||
Total other deductions | $ | 31 | $ | 97 | $ | 1,301 | ||||||
| (a) | Reported in Corporate and Other segment, except for $687 million of debt extinguishment gain reported in Competitive Electric segment. |
| (b) | In November 2010, the counterparty to a long-term power sales agreement terminated the contract, which had a remaining term of 27 years. The contract was a derivative and subject to mark-to-market accounting. The termination resulted in a noncash gain of $116 million, which represented the derivative liability as of the termination date. |
| (c) | Reported in Competitive Electric segment. |
| (d) | 2008 amount represents insurance recovery for damage to mining equipment. |
| (e) | Includes $23 million for reversal of a use tax accrual, related to periods prior to the Merger, due to a state ruling in 2009 (reported in Competitive Electric segment) and $21 million for reversal of excess exit liabilities recorded in connection with the termination of outsourcing arrangements (see Note 19) (reported in Competitive Electric ($11 million) and Regulated Delivery segments ($10 million)). |
| (f) | Reported in Regulated Delivery segment. |
| (g) | Represents reserve established against amounts due (excluding termination related costs) from subsidiaries of Lehman Brothers Holdings Inc. (Lehman) arising from commodity hedging and trading activities. Reported in Competitive Electric segment. |
| (h) | Includes post-Merger consulting expenses related to optimizing business performance. Reported in Corporate and Other activities. |
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| 10. | TRADE ACCOUNTS RECEIVABLE AND ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM |
TXU Energy participates in EFH Corp.’s accounts receivable securitization program with financial institutions (the funding entities). Under the program, TXU Energy (originator) sells trade accounts receivable to TXU Receivables Company, which is an entity created for the special purpose of purchasing receivables from the originator and is a consolidated, wholly-owned, bankruptcy-remote, direct subsidiary of EFH Corp. TXU Receivables Company sells undivided interests in the purchased accounts receivable for cash to entities established for this purpose by the funding entities. In accordance with the amended transfers and servicing accounting standard as discussed in Note 1, the trade accounts receivable amounts under the program are reported as pledged balances, and the related funding amounts are reported as short-term borrowings. Prior to the January 1, 2010 effective date of the new accounting standard, the activity was accounted for as a sale of accounts receivable in accordance with previous accounting standards, which resulted in the funding being recorded as a reduction of accounts receivable.
In June 2010, the accounts receivable securitization program was amended. The amendments, among other things, reduced the maximum funding amount under the program to $350 million from $700 million. Program funding declined from $383 million as of December 31, 2009 to $96 million as of December 31, 2010. Under the terms of the program, available funding was reduced by $38 million of customer deposits held by the originator because TCEH’s credit ratings were lower than Ba3/BB-. The declines in actual and maximum funding amounts reflected exclusion of receivables under contractual sales agreements.
All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Ongoing changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, reflect seasonal variations in the level of accounts receivable, changes in collection trends and other factors such as changes in sales prices and volumes. TXU Receivables Company has issued a subordinated note payable to the originator for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originator that was funded by the sale of the undivided interests. The subordinated note issued by TXU Receivables Company is subordinated to the undivided interests of the funding entities in the purchased receivables. The balance of the subordinated note payable, which is eliminated in consolidation, totaled $516 million and $463 million as of December 31, 2010 and 2009, respectively.
The discount from face amount on the purchase of receivables from the originator principally funds program fees paid to the funding entities. The program fees consist primarily of interest costs on the underlying financing. Consistent with the change in balance sheet presentation of the funding discussed above, the program fees are currently reported as interest expense and related charges but were previously reported as losses on sale of receivables reported in SG&A expense. The discount also funds a servicing fee, which is reported as SG&A expense, paid by TXU Receivables Company to EFH Corporate Services Company (Service Co.), a direct wholly-owned subsidiary of EFH Corp., which provides recordkeeping services and is the collection agent for the program.
Program fee amounts were as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Program fees | $ | 10 | $ | 12 | $ | 25 | ||||||
Program fees as a percentage of average funding (annualized) | 3.8 | % | 2.4 | % | 5.2 | % | ||||||
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Activities of TXU Receivables Company were as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Cash collections on accounts receivable | $ | 6,334 | $ | 6,125 | $ | 6,393 | ||||||
Face amount of new receivables purchased | (6,100 | ) | (6,287 | ) | (6,418 | ) | ||||||
Discount from face amount of purchased receivables | 12 | 14 | 29 | |||||||||
Program fees paid to funding entities | (10 | ) | (12 | ) | (25 | ) | ||||||
Servicing fees paid to Service Co. for recordkeeping and collection services | (2 | ) | (2 | ) | (4 | ) | ||||||
Increase (decrease) in subordinated notes payable | 53 | 195 | (28 | ) | ||||||||
Financing/operating cash flows used by (provided to) originator under the program | $ | 287 | $ | 33 | $ | (53 | ) | |||||
Changes in funding under the program have previously been reported as operating cash flows, and the amended accounting rule requires that the amount of funding under the program as of the January 1, 2010 adoption ($383 million) be reported as a use of operating cash flows and a source of financing cash flows. All changes in funding subsequent to adoption of the amended standard are reported as financing activities.
The program, which expires in October 2013, may be terminated upon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds, and the funding entities do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Receivables Company or Service Co. defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities, or if TCEH, any affiliate of TCEH acting as collection agent other than Service Co., any parent guarantor of the originator or the originator shall default in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. As of December 31, 2010, there were no such events of termination.
Upon termination of the program, liquidity would be reduced as collections of sold receivables would be used by TXU Receivables Company to repurchase the undivided interests from the funding entities instead of purchasing new receivables. The level of cash flows would normalize in approximately 16 to 30 days.
Trade Accounts Receivable
| December 31, | ||||||||
| 2010 (a) | 2009 | |||||||
Wholesale and retail trade accounts receivable, including $612 in pledged retail receivables as of December 31, 2010 | $ | 1,063 | $ | 1,726 | ||||
Undivided interests in retail accounts receivable sold by TXU Receivables Company | — | (383 | ) | |||||
Allowance for uncollectible accounts | (64 | ) | (83 | ) | ||||
Trade accounts receivable — reported in balance sheet | $ | 999 | $ | 1,260 | ||||
| (a) | See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010. |
Gross trade accounts receivable as of December 31, 2010 and 2009 included unbilled revenues of $297 million and $546 million, respectively.
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Allowance for Uncollectible Accounts Receivable
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Allowance for uncollectible accounts receivable as of beginning of period | $ | 81 | $ | 70 | $ | 32 | ||||||
Increase for bad debt expense | 108 | 113 | 81 | |||||||||
Decrease for account write-offs | (125 | ) | (99 | ) | (69 | ) | ||||||
Charge related to Lehman bankruptcy | — | — | 26 | |||||||||
Other | — | (1 | ) | — | ||||||||
Allowance for uncollectible accounts receivable as of end of period | $ | 64 | $ | 83 | $ | 70 | ||||||
Receivables from Unconsolidated Subsidiary
Receivables from unconsolidated subsidiary are measured at historical cost and primarily consist of Oncor’s obligation under the EFH Corp. pension and OPEB plans. EFH Corp. reviews Oncor’s credit scores to assess the overall collectability of its affiliated receivables, which totaled $1.463 billion as of December 31, 2010. There were no credit loss allowances as of December 31, 2010. See Note 22 for additional information about related party transactions.
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| 11. | SHORT-TERM BORROWINGS AND LONG-TERM DEBT |
Short-Term Borrowings
As of December 31, 2010, outstanding short-term borrowings totaled $1.221 billion, which included $1.125 billion under TCEH credit facilities at a weighted average interest rate of 3.80%, excluding certain customary fees, and $96 million under the accounts receivable securitization program discussed in Note 10.
As of December 31, 2009, we had outstanding short-term borrowings of $1.569 billion at a weighted average interest rate of 2.50%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $953 million for TCEH and $616 million for Oncor.
Credit Facilities
Credit facilities with cash borrowing and/or letter of credit availability as of December 31, 2010 are presented below. The facilities are all senior secured facilities of TCEH.
| As of December 31, 2010 | ||||||||||||||||||||
Authorized Borrowers and Facility | Maturity Date | Facility Limit | Letters of Credit | Cash Borrowings | Availability | |||||||||||||||
TCEH Revolving Credit Facility (a) | October 2013 | $ | 2,700 | $ | — | $ | 1,125 | $ | 1,440 | |||||||||||
TCEH Letter of Credit Facility (b) | October 2014 | 1,250 | — | 1,250 | — | |||||||||||||||
Subtotal TCEH | $ | 3,950 | $ | — | $ | 2,375 | $ | 1,440 | ||||||||||||
TCEH Commodity Collateral Posting Facility (c) | December 2012 | Unlimited | $ | — | $ | — | Unlimited | |||||||||||||
| (a) | Facility used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount includes $94 million of commitments from Lehman that are only available from the fronting banks and the swingline lender and excludes $135 million of requested cash draws that have not been funded by Lehman. All outstanding borrowings under this facility as of December 31, 2010 bear interest at LIBOR plus 3.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion of the facility. |
| (b) | Facility used for issuing letters of credit for general corporate purposes, including, but not limited to, providing collateral support under hedging arrangements and other commodity transactions that are not eligible for funding under the TCEH Commodity Collateral Posting Facility. The borrowings under this facility were drawn at the inception of the facility, are classified as long-term debt, and except for $115 million related to a letter of credit drawn in June 2009, have been retained as restricted cash. Letters of credit totaling $874 million issued as of December 31, 2010 are supported by the restricted cash, and the remaining letter of credit availability totals $261 million. |
| (c) | Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 330 million MMBtu as of December 31, 2010. As of December 31, 2010, there were no borrowings under this facility. See “TCEH Senior Secured Facilities” below for additional information. |
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Long-Term Debt
As of December 31, 2010 and December 31, 2009, long-term debt consisted of the following:
| December 31, 2010 | December 31, 2009 | |||||||
| TCEH | ||||||||
Pollution Control Revenue Bonds: | ||||||||
Brazos River Authority: | ||||||||
5.400% Fixed Series 1994A due May 1, 2029 | $ | 39 | $ | 39 | ||||
7.700% Fixed Series 1999A due April 1, 2033 | 111 | 111 | ||||||
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013 (a) | 16 | 16 | ||||||
7.700% Fixed Series 1999C due March 1, 2032 | 50 | 50 | ||||||
8.250% Fixed Series 2001A due October 1, 2030 | 71 | 71 | ||||||
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011 (a) | 217 | 217 | ||||||
8.250% Fixed Series 2001D-1 due May 1, 2033 | 171 | 171 | ||||||
0.320% Floating Series 2001D-2 due May 1, 2033 (b) | 97 | 97 | ||||||
0.310% Floating Taxable Series 2001I due December 1, 2036 (c) | 62 | 62 | ||||||
0.320% Floating Series 2002A due May 1, 2037 (b) | 45 | 45 | ||||||
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (a) | 44 | 44 | ||||||
6.300% Fixed Series 2003B due July 1, 2032 | 39 | 39 | ||||||
6.750% Fixed Series 2003C due October 1, 2038 | 52 | 52 | ||||||
5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014 (a) | 31 | 31 | ||||||
5.000% Fixed Series 2006 due March 1, 2041 | 100 | 100 | ||||||
Sabine River Authority of Texas: | ||||||||
6.450% Fixed Series 2000A due June 1, 2021 | 51 | 51 | ||||||
5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011 (a) | 91 | 91 | ||||||
5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011 (a) | 107 | 107 | ||||||
5.200% Fixed Series 2001C due May 1, 2028 | 70 | 70 | ||||||
5.800% Fixed Series 2003A due July 1, 2022 | 12 | 12 | ||||||
6.150% Fixed Series 2003B due August 1, 2022 | 45 | 45 | ||||||
Trinity River Authority of Texas: | ||||||||
6.250% Fixed Series 2000A due May 1, 2028 | 14 | 14 | ||||||
Unamortized fair value discount related to pollution control revenue bonds (d) | (132 | ) | (147 | ) | ||||
Senior Secured Facilities: | ||||||||
3.764% TCEH Initial Term Loan Facility maturing October 10, 2014 (e)(f)(g) | 15,895 | 16,079 | ||||||
3.764% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (e)(f) | 4,034 | 4,075 | ||||||
3.761% TCEH Letter of Credit Facility maturing October 10, 2014 (f) | 1,250 | 1,250 | ||||||
0.250% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (h) | — | — | ||||||
Other: | ||||||||
10.25% Fixed Senior Notes due November 1, 2015 (i) | 1,873 | 2,944 | ||||||
10.25% Fixed Senior Notes due November 1, 2015, Series B (i) | 1,292 | 1,913 | ||||||
10.50 / 11.25% Senior Toggle Notes due November 1, 2016 | 1,406 | 1,952 | ||||||
15.00% Senior Secured Second Lien Notes due April 1, 2021 | 336 | — | ||||||
15.00% Senior Secured Second Lien Notes due April 1, 2021, Series B | 1,235 | — | ||||||
7.000% Fixed Senior Notes due March 15, 2013 | 5 | 5 | ||||||
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015 | 42 | 55 | ||||||
Capital lease obligations | 76 | 153 | ||||||
Other | 3 | — | ||||||
Unamortized fair value discount (d) | (2 | ) | (4 | ) | ||||
Total TCEH | $ | 28,848 | $ | 29,810 | ||||
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| December 31, 2010 | December 31, 2009 | |||||||
| EFCH | ||||||||
9.580% Fixed Notes due in semiannual installments through December 4, 2019 | $ | 46 | $ | 51 | ||||
8.254% Fixed Notes due in quarterly installments through December 31, 2021 | 46 | 50 | ||||||
1.087% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (f) | 1 | 1 | ||||||
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037 | 8 | 8 | ||||||
Unamortized fair value discount (d) | (10 | ) | (11 | ) | ||||
Total EFCH | 91 | 99 | ||||||
| EFH Corp. (parent entity) | ||||||||
10.875% Fixed Senior Notes due November 1, 2017 (j) | 359 | 1,831 | ||||||
11.25 / 12.00% Senior Toggle Notes due November 1, 2017 (j) | 571 | 2,797 | ||||||
9.75% Fixed Senior Secured Notes due October 15, 2019 | 115 | 115 | ||||||
10.000% Fixed Senior Secured Notes due January 15, 2020 | 1,061 | — | ||||||
5.550% Fixed Senior Notes Series P due November 15, 2014 (k) | 434 | 983 | ||||||
6.500% Fixed Senior Notes Series Q due November 15, 2024 (k) | 740 | 740 | ||||||
6.550% Fixed Senior Notes Series R due November 15, 2034 (k) | 744 | 744 | ||||||
8.820% Building Financing due semiannually through February 11, 2022 (l) | 68 | 75 | ||||||
Unamortized fair value premium related to Building Financing (d) | 15 | 17 | ||||||
Capital lease obligations | 4 | — | ||||||
Unamortized fair value discount (d) | (476 | ) | (599 | ) | ||||
Total EFH Corp. | 3,635 | 6,703 | ||||||
| EFIH | ||||||||
9.75% Fixed Senior Secured Notes due October 15, 2019 | 141 | 141 | ||||||
10.000% Fixed Senior Secured Notes due December 1, 2020 | 2,180 | — | ||||||
Total EFIH | 2,321 | 141 | ||||||
| Oncor (m) (n) | ||||||||
6.375% Fixed Senior Notes due May 1, 2012 | — | 700 | ||||||
5.950% Fixed Senior Notes due September 1, 2013 | — | 650 | ||||||
6.375% Fixed Senior Notes due January 15, 2015 | — | 500 | ||||||
6.800% Fixed Senior Notes due September 1, 2018 | — | 550 | ||||||
7.000% Fixed Debentures due September 1, 2022 | — | 800 | ||||||
7.000% Fixed Senior Notes due May 1, 2032 | — | 500 | ||||||
7.250% Fixed Senior Notes due January 15, 2033 | — | 350 | ||||||
7.500% Fixed Senior Notes due September 1, 2038 | — | 300 | ||||||
Unamortized discount | — | (15 | ) | |||||
Total Oncor | — | 4,335 | ||||||
Oncor Electric Delivery Transition Bond Company LLC (n) (o) | ||||||||
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010 | — | 13 | ||||||
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013 | — | 130 | ||||||
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015 | — | 145 | ||||||
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012 | — | 197 | ||||||
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016 | — | 290 | ||||||
Total Oncor Electric Delivery Transition Bond Company LLC | — | 775 | ||||||
Unamortized fair value discount related to transition bonds (d) | — | (6 | ) | |||||
Total Oncor consolidated | — | 5,104 | ||||||
Total EFH Corp. consolidated | 34,895 | 41,857 | ||||||
Less amount due currently | (669 | ) | (417 | ) | ||||
Total long-term debt | $ | 34,226 | $ | 41,440 | ||||
| (a) | These series are in the multiannual interest rate mode and are subject to mandatory tender prior to maturity on the mandatory remarketing date. On such date, the interest rate and interest rate period will be reset for the bonds. |
| (b) | Interest rates in effect as of December 31, 2010. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit. |
| (c) | Interest rate in effect as of December 31, 2010. This series is in a weekly interest rate mode and is classified as long-term as it is supported by long-term irrevocable letters of credit. |
| (d) | Amount represents unamortized fair value adjustments recorded under purchase accounting. |
| (e) | Interest rate swapped to fixed on $15.80 billion principal amount. |
| (f) | Interest rates in effect as of December 31, 2010. |
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| (g) | 2010 amount excludes $20 million that is held by EFH Corp. and eliminated in consolidation. |
| (h) | Interest rate in effect as of December 31, 2010, excluding a quarterly maintenance fee of $11 million. See “Credit Facilities” above for more information. |
| (i) | 2010 amounts exclude $173 million and $150 million of the TCEH Senior Notes and TCEH Senior Notes, Series B, respectively, that are held either by EFH Corp. or EFIH and eliminated in consolidation. |
| (j) | 2010 amounts exclude $1.428 billion and $2.296 billion of EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes, respectively, that are held by EFIH and eliminated in consolidation. |
| (k) | Amounts exclude $9 million, $6 million and $3 million of the Series P, Series Q and Series R notes, respectively, that are held by EFIH and eliminated in consolidation. |
| (l) | This financing is secured and will be serviced with cash drawn by the beneficiary of a letter of credit. |
| (m) | Secured with first priority lien. |
| (n) | See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010. |
| (o) | These bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset. |
Debt-Related Activity in 2010— Repayments of long-term debt in 2010 totaling $309 million included $205 million of principal payments at scheduled maturity dates as well as other repayments totaling $104 million principally related to capitalized leases. See “2010 Debt Exchanges, Repurchases and Issuances” below for discussion of $6.904 billion principal amount of debt acquired in debt exchanges and repurchases completed in the year ended December 31, 2010.
During 2010, EFH Corp. issued, through the payment-in-kind (PIK) election, $194 million principal amount of its 11.25%/12.00% Senior Toggle Notes due November 2017 (EFH Corp. Toggle Notes), and TCEH issued, through the PIK election, $205 million principal amount of its 10.50%/11.25% Senior Toggle Notes due November 2016 (TCEH Toggle Notes), in each case, in lieu of making cash interest payments.
2010 Debt Exchanges, Repurchases and Issuances — Debt exchanges and repurchases completed in 2010 resulted in acquisitions of $6.904 billion aggregate principal amount of outstanding EFH Corp. and TCEH debt with due dates largely 2017 or earlier in exchange for $3.962 billion aggregate principal amount of new debt and $1.042 billion in cash. The new debt issued in exchange transactions consisted of $2.180 billion aggregate principal amount of EFIH 10% Notes due 2020, $561 million aggregate principal amount of EFH Corp. 10% Notes due 2020, $336 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021 and $885 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021 (Series B). EFH Corp. also issued $500 million principal amount of EFH Corp. 10% Notes due 2020 for cash, and TCEH issued $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) due 2021 for cash. A discussion of these transactions and descriptions of the EFIH 10% Notes, EFH Corp. 10% Notes and TCEH 15% Senior Secured Second Lien Notes are presented below.
Transactions completed in the year ended December 31, 2010 were as follows:
| • | In November, TCEH and TCEH Finance issued $885 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) due 2021 in exchange for $850 million aggregate principal amount of TCEH 10.25% Notes and $420 million aggregate principal amount of TCEH Toggle Notes. |
| • | In October, TCEH and TCEH Finance issued $336 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes due 2021 in exchange for $423 million aggregate principal amount of TCEH 10.25% Notes (plus accrued interest paid in cash) and $55 million aggregate principal amount of TCEH Toggle Notes (together, the TCEH Senior Notes). |
| • | In October, TCEH and TCEH Finance issued $350 million aggregate principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) due 2021, and used the $343 million of net proceeds to repurchase $240 million principal amount of TCEH 10.25% Notes (including $14 million from EFH Corp.) and $283 million principal amount of TCEH Toggle Notes (including $83 million from EFH Corp.) and paid accrued interest from cash on hand. TCEH paid $53 million of the net proceeds for the TCEH notes held by EFH Corp., which were retired. |
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| • | In a public (registered with the SEC) debt exchange transaction in August, EFIH and EFIH Finance (together, the Issuers) issued $2.180 billion aggregate principal amount of EFIH 10% Notes due 2020 and paid $500 million in cash, plus accrued interest, in exchange for $2.166 billion aggregate principal amount of EFH Corp. Toggle Notes and $1.428 billion aggregate principal amount of EFH Corp. 10.875% Notes (together, the EFH Corp. Senior Notes). |
| • | Between April and July, EFH Corp. issued $527 million principal amount of EFH Corp. 10% Notes due 2020 in exchange for $549 million principal amount of EFH Corp. 5.55% Series P Senior Notes (EFH Corp. 5.55% Notes), $110 million principal amount of EFH Corp. Toggle Notes, $25 million principal amount of EFH Corp. 10.875% Notes, $13 million principal amount of TCEH 10.25% Notes and $17 million principal amount of TCEH Toggle Notes. |
| • | In March, EFH Corp. issued $34 million principal amount of EFH Corp. 10% Notes due 2020 in exchange for $20 million principal amount of EFH Corp. Toggle Notes and $27 million principal amount of TCEH Toggle Notes. |
| • | In January, EFH Corp. issued $500 million aggregate principal amount of EFH Corp. 10% Notes due 2020, with the proceeds intended to be used for general corporate purposes including debt exchanges and repurchases. |
| • | In addition, from time to time in 2010, EFH Corp. repurchased $124 million principal amount of EFH Corp. Toggle Notes, $19 million principal amount of EFH Corp. 10.875% Notes, $181 million principal amount of TCEH 10.25% Notes, $32 million principal amount of TCEH Toggle Notes and $20 million principal amount of initial term loans under the TCEH Senior Secured Facilities for $252 million in cash plus accrued interest. |
These transactions resulted in debt extinguishment gains totaling $1.814 billion (reported as other income).
In connection with the debt exchange transactions, EFH Corp. received the requisite consents from holders of the EFH Corp. Senior Notes and EFH Corp. 5.55% Notes applicable to certain amendments to the respective indentures governing such notes. These amendments, among other things, eliminated substantially all of the restrictive covenants, eliminated certain events of default, modified covenants regarding mergers and consolidations and modified or eliminated certain other provisions in such indentures.
The EFH Corp. notes acquired by EFIH and the majority of the TCEH notes and initial term loans under the TCEH Senior Secured Facilities acquired by EFH Corp. are held as investments by EFIH and EFH Corp., and are eliminated in consolidation. All other securities acquired in the above transactions have been cancelled.
Debt-Related Activity in 2009— Repayments of long-term debt in 2009 totaling $396 million represented principal payments at scheduled maturity dates as well as other repayments totaling $50 million, principally related to capitalized leases. Payments at scheduled amortization or maturity dates included $165 million repaid under the TCEH Initial Term Loan Facility, $104 million of Oncor transition bond principal payments, $65 million repaid under a TCEH promissory note, $9 million repaid under the TCEH Delayed Draw Term Loan Facility and $3 million of EFH Corp. senior notes.
Increases in long-term debt during 2009 totaling $522 million consisted of increased borrowings under the TCEH Delayed Draw Term Loan Facility, which was fully drawn as of July 2009, to fund expenditures related to construction of new generation facilities and environmental upgrades of existing lignite/coal-fueled generation facilities. In addition, long-term debt increased as a result of EFH Corp. increasing, through the PIK election, the principal amount of its EFH Corp. Toggle Notes by $309 million, and TCEH increasing, through the PIK election, the principal amount of its TCEH Toggle Notes by $202 million, in each case, in lieu of making cash interest payments.
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2009 Debt Exchanges — In November 2009, EFH Corp., EFIH and EFIH Finance completed debt exchange transactions, which resulted in the issuance of $115 million principal amount of 9.75% Senior Secured Notes due 2019 by EFH Corp. (the EFH Corp. 9.75% Notes) and $141 million principal amount of 9.75% Senior Secured Notes due 2019 by EFIH and EFIH Finance (the EFIH 9.75% Notes) (both discussed further below) in exchange for $169 million principal amount of EFH Corp. 10.875% Notes, $12 million principal amount of EFH Corp. Toggle Notes, $143 million principal amount of TCEH 10.25% Notes, $17 million of EFH Corp. 5.55% Series P Senior Notes, $10 million of EFH Corp. 6.50% Series Q Senior Notes and $6 million principal amount of EFH Corp. 6.55% Series R Senior Notes.
Maturities— Long-term debt maturities as of December 31, 2010 are as follows:
Year | ||||
2011 | $ | 651 | ||
2012 | 237 | |||
2013 | 296 | |||
2014 | 21,046 | |||
2015 | 3,187 | |||
Thereafter (a) | 10,003 | |||
Unamortized fair value premium | 15 | |||
Unamortized fair value discount (b) | (620 | ) | ||
Capital lease obligations | 80 | |||
Total | $ | 34,895 | ||
| (a) | Long-term debt maturities for EFH Corp. (parent entity) total $7.766 billion, including $3.742 billion held by EFIH that is not included above. |
| (b) | Unamortized fair value discount for EFH Corp. (parent entity) totals $(476) million. |
TCEH Senior Secured Facilities—The applicable rate on borrowings under the TCEH Initial Term Loan Facility, the TCEH Delayed Draw Term Loan Facility, the TCEH Revolving Credit Facility and the TCEH Letter of Credit Facility as of December 31, 2010 is provided in the long-term debt table and in the discussion of short-term borrowings above and reflects LIBOR-based borrowings. These borrowings totaled $22.304 billion as of December 31, 2010, excluding $20 million held by EFH Corp. as a result of debt repurchases.
In August 2009, the TCEH Senior Secured Facilities were amended to reduce the existing first lien capacity under the TCEH Senior Secured Facilities by $1.25 billion in exchange for the ability for TCEH to issue up to an additional $4 billion of secured notes or loans ranking junior to TCEH’s first lien obligations, provided that:
| • | such notes or loans mature later than the latest maturity date of any of the initial term loans under the TCEH Senior Secured Facilities, and |
| • | any net cash proceeds from any such issuances are used (i) in exchange for, or to refinance, repay, retire, refund or replace indebtedness of TCEH or (ii) to acquire, directly or indirectly, all or substantially all of the property and assets or business of another person or to finance the purchase price, cost of design, acquisition, construction, repair, restoration, replacement, expansion, installation or improvement of certain fixed or capital assets. |
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In addition, the amended facilities permit TCEH to, among other things:
| • | issue new secured notes or loans, which may include, in each case, debt secured on a pari passu basis with the obligations under the TCEH Senior Secured Facilities, so long as, in each case, among other things, the net cash proceeds from any such issuance are used to prepay certain loans under the TCEH Senior Secured Facilities at par; |
| • | upon making an offer to all lenders within a particular series, agree with lenders of that series to extend the maturity of their term loans or extend or refinance their revolving credit commitments under the TCEH Senior Secured Facilities, and pay increased interest rates or otherwise modify the terms of their loans or revolving commitments in connection with such an extension, and |
| • | exclude from the financial maintenance covenant under the TCEH Senior Secured Facilities any new debt issued that ranks junior to TCEH’s first lien obligations under the TCEH Senior Secured Facilities. |
Under the terms of the TCEH Senior Secured Facilities, the commitments of the lenders to make loans to TCEH are several and not joint. Accordingly, if any lender fails to make loans to TCEH, TCEH’s available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the TCEH Senior Secured Facilities.
The TCEH Senior Secured Facilities are unconditionally guaranteed jointly and severally on a senior secured basis by EFCH, and subject to certain exceptions, each existing and future direct or indirect wholly-owned US restricted subsidiary of TCEH. The TCEH Senior Secured Facilities, including the guarantees thereof, certain commodity hedging transactions and the interest rate swaps described under “TCEH Interest Rate Swap Transactions” below are secured by (a) substantially all of the current and future assets of TCEH and TCEH’s subsidiaries who are guarantors of such facilities and (b) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.
The TCEH Initial Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of such facility ($41 million quarterly), with the balance payable in October 2014. The TCEH Delayed Draw Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the actual principal outstanding under such facility as of December 2009 ($10 million quarterly), with the balance payable in October 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time until October 2013. The TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility will mature in October 2014 and December 2012, respectively.
The TCEH Senior Secured Facilities contain customary negative covenants that, among other things, restrict, subject to certain exceptions, TCEH and its restricted subsidiaries’ ability to:
| • | incur additional debt; |
| • | create additional liens; |
| • | enter into mergers and consolidations; |
| • | sell or otherwise dispose of assets; |
| • | make dividends, redemptions or other distributions in respect of capital stock; |
| • | make acquisitions, investments, loans and advances, and |
| • | pay or modify certain subordinated and other material debt. |
In addition, the TCEH Senior Secured Facilities contain a maintenance covenant that prohibits TCEH and its restricted subsidiaries from exceeding a maximum consolidated secured leverage ratio and to observe certain customary reporting requirements and other affirmative covenants.
The TCEH Senior Secured Facilities contain certain customary events of default for senior leveraged acquisition financings, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments.
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TCEH 15% Senior Secured Second Lien Notes —The TCEH 15% Senior Secured Second Lien Notes and the TCEH 15% Senior Secured Second Lien Notes (Series B) (collectively, the TCEH Senior Secured Second Lien Notes) mature in April 2021, with interest payable in cash quarterly in arrears on January 1, April 1, July 1 and October 1, beginning January 1, 2011, at a fixed rate of 15% per annum. The notes are unconditionally guaranteed on a joint and several basis by EFCH and, subject to certain exceptions, each subsidiary of TCEH (collectively, the Guarantors). The notes are secured, on a second-priority basis, by security interests in all of the assets of TCEH, and the guarantees (other than the guarantee of EFCH) are secured on a second-priority basis by all of the assets and equity interests of all of the Guarantors other than EFCH (collectively, the Subsidiary Guarantors), in each case, to the extent such assets and security interests secure obligations under the TCEH Senior Secured Credit Facilities on a first-priority basis (the TCEH Collateral), subject to certain exceptions (including the elimination of the pledge of equity interests of any subsidiary Guarantor to the extent that separate financial statements would be required to be filed with the SEC for such subsidiary Guarantor under Rule 3-16 of Regulation S-X) and permitted liens. The guarantee from EFCH is not secured.
As of December 31, 2010, there were $1.571 billion total principal amount of TCEH Senior Secured Second Lien Notes. The TCEH Senior Secured Second Lien Notes are a senior obligation and rank equally in right of payment with all senior indebtedness of TCEH, are senior in right of payment to all existing or future unsecured debt of TCEH to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral) and are senior in right of payment to any future subordinated debt of TCEH. These notes are effectively subordinated to TCEH’s obligations under the TCEH Senior Secured Credit Facilities and TCEH’s commodity and interest rate hedges that are secured by a first-priority lien on the TCEH Collateral and any future obligations subject to first-priority liens on the TCEH Collateral, to the extent of the value of the TCEH Collateral, and to all secured obligations of TCEH that are secured by assets other than the TCEH Collateral, to the extent of the value of the assets securing such obligations.
The guarantees of the TCEH Senior Secured Second Lien Notes by the Subsidiary Guarantors are effectively senior to any unsecured debt of the Subsidiary Guarantors to the extent of the value of the TCEH Collateral (after taking into account any first-priority liens on the TCEH Collateral). These guarantees are effectively subordinated to all debt of the Subsidiary Guarantors secured by the TCEH Collateral on a first-priority basis or that is secured by assets that are not part of the TCEH Collateral, to the extent of the value of the collateral securing that debt. EFCH’s guarantee ranks equally with its unsecured debt (including debt it guarantees on an unsecured basis) and is effectively subordinated to any of its secured debt to the extent of the value of the collateral securing that debt.
The indenture for the TCEH Senior Secured Second Lien Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, TCEH’s and its restricted subsidiaries’ ability to:
| • | make restricted payments, including certain investments; |
| • | incur debt and issue preferred stock; |
| • | create liens; |
| • | enter into mergers or consolidations; |
| • | sell or otherwise dispose of certain assets, and |
| • | engage in certain transactions with affiliates. |
The indenture also contains customary events of default, including, among others, failure to pay principal or interest on the notes when due. In general, all of the series of TCEH Senior Secured Second Lien Notes vote together as a single class. As a result, if certain events of default occur under the indenture, the trustee or the holders of at least 30% of aggregate principal amount of all outstanding TCEH Senior Secured Second Lien Notes may declare the principal amount on all such notes to be due and payable immediately.
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Until October 1, 2013, TCEH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of each series of the TCEH Senior Secured Second Lien Notes from time to time at a redemption price of 115.00% of the aggregate principal amount of the notes being redeemed, plus accrued interest. TCEH may redeem each series of the notes at any time prior to October 1, 2015 at a price equal to 100% of their principal amount, plus accrued interest and the applicable premium as defined in the indenture. TCEH may also redeem each series of the notes, in whole or in part, at any time on or after October 1, 2015, at specified redemption prices, plus accrued interest. Upon the occurrence of a change of control (as described in the indenture), TCEH must offer to repurchase each series of the notes at 101% of their principal amount, plus accrued interest.
The TCEH Senior Secured Second Lien Notes were issued in private placements and have not been registered under the Securities Act. TCEH has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the TCEH Senior Secured Second Lien Notes (except for provisions relating to transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the TCEH Senior Secured Second Lien Notes unless such notes meet certain transferability conditions (as described in the related registration rights agreement). If the registration statement has not been filed and declared effective within 365 days after the original issue date (a Registration Default), the annual interest rate on the notes will increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter the annual interest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues. If the Registration Default is cured, the interest rate on the notes will revert to the original level.
TCEH Senior Notes—The TCEH 10.25% Notes mature in November 2015, with interest payable in cash semi-annually in arrears on May 1 and November 1 at a fixed rate of 10.25% per annum. The TCEH Toggle Notes mature in November 2016, with interest payable semi-annually in arrears on May 1 and November 1 at a fixed rate of 10.50% per annum for cash interest and at a fixed rate of 11.25% per annum for PIK Interest. For any interest period until November 2012, TCEH may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new TCEH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Once TCEH makes a PIK election, the election is valid for each succeeding interest payment period until TCEH revokes the election.
The TCEH 10.25% and Toggle Notes (collectively, the TCEH Senior Notes) had a total principal amount as of December 31, 2010 of $4.570 billion (excluding $323 million principal amount held by EFH Corp. and EFIH) and are fully and unconditionally guaranteed on a joint and several unsecured basis by TCEH’s direct parent, EFCH (which owns 100% of TCEH and its subsidiary guarantors), and by each subsidiary that guarantees the TCEH Senior Secured Facilities.
TCEH may redeem the TCEH 10.25% Notes and TCEH Toggle Notes at any time prior to November 1, 2011 and 2012, respectively, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. TCEH may redeem the TCEH 10.25% Notes and TCEH Toggle Notes, in whole or in part, at any time on or after November 1, 2011 and 2012, respectively, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFCH or TCEH, TCEH must offer to repurchase the TCEH Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
The indenture for the TCEH Senior Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, TCEH’s and its restricted subsidiaries’ ability to:
| • | make restricted payments; |
| • | incur debt and issue preferred stock; |
| • | create liens; |
| • | enter into mergers or consolidations; |
| • | sell or otherwise dispose of certain assets, and |
| • | engage in certain transactions with affiliates. |
The indenture also contains customary events of default, including, among others, failure to pay principal or interest on the notes when due. If certain events of default occur and are continuing under the indenture, the trustee or the holders of at least 30% in principal amount of the notes may declare the principal amount on the notes to be due and payable immediately.
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EFH Corp. 10% Notes— The EFH Corp. 10% Notes mature in January 2020, with interest payable in cash semi-annually in arrears on January 15 and July 15 at a fixed rate of 10% per annum. The notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and EFIH. The guarantee from EFIH is secured by EFIH’s pledge of 100% of the membership interests and other investments it owns in Oncor Holdings (such membership interests and other investments, the EFIH Collateral). The guarantee from EFCH is not secured. EFIH’s guarantee of the EFH Corp. 10% Notes is secured by the EFIH Collateral on an equal and ratable basis with the EFIH Notes and EFIH’s guarantee of the EFH Corp. 9.75% Notes.
As of December 31, 2010, there were $1.061 billion total principal amount of EFH Corp. 10% Notes. The EFH Corp. 10% Notes are a senior obligation and rank equally in right of payment with all senior indebtedness of EFH Corp. and are senior in right of payment to any future subordinated indebtedness of EFH Corp. These notes are effectively subordinated to any indebtedness of EFH Corp. secured by assets of EFH Corp. to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other liabilities of EFH Corp.’s non-guarantor subsidiaries.
The guarantees of the EFH Corp. 10% Notes are the general senior obligations of each guarantor and rank equally in right of payment with all existing and future senior indebtedness of each guarantor. The guarantee from EFIH is effectively senior to all unsecured indebtedness of EFIH to the extent of the value of the EFIH Collateral. The guarantees are effectively subordinated to all secured indebtedness of each guarantor secured by assets other than the EFIH Collateral to the extent of the value of the assets securing such indebtedness and are structurally subordinated to any existing and future indebtedness and liabilities of EFH Corp.’s subsidiaries that are not guarantors.
The indenture for the EFH Corp. 10% Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, EFH Corp.’s and its restricted subsidiaries’ ability to:
| • | make restricted payments; |
| • | incur debt and issue preferred stock; |
| • | create liens; |
| • | enter into mergers or consolidations; |
| • | sell or otherwise dispose of certain assets, and |
| • | engage in certain transactions with affiliates. |
These notes and indenture also contain customary events of default, including, among others, failure to pay principal or interest on the notes when due. If certain events of default occur and are continuing under these notes and the indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes may declare the principal amount of the notes to be due and payable immediately.
Until January 15, 2013, EFH Corp. may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the EFH Corp. 10% Notes from time to time at a redemption price of 110.000% of the aggregate principal amount of the notes being redeemed, plus accrued and unpaid interest. EFH Corp. may redeem the notes at any time prior to January 15, 2015 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. EFH Corp. may also redeem the notes, in whole or in part, at any time on or after January 15, 2015, at specified redemption prices, plus accrued and unpaid interest. Upon the occurrence of a change of control (as described in the indenture), EFH Corp. must offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest.
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The EFH Corp. 10% Notes were issued in private placements with registration rights. EFH Corp. has offered to exchange notes that have substantially identical terms as the EFH Corp. 10% Notes (other than transfer restrictions). The exchange offer is expected to be completed in March 2011. Because the exchange offer was not completed within 360 days after the issue date of the EFH Corp. 10% Notes, the annual interest rate on the EFH Corp. 10% Notes increased by 25 basis points effective January 8, 2011 and will remain at that level until the exchange offer closes. Once the exchange offer closes, the interest rate on the notes will revert to the original level.
EFH Corp. Senior Notes —The EFH Corp. 10.875% Notes mature in November 2017, with interest payable in cash semi-annually in arrears on May 1 and November 1 at a fixed rate of 10.875% per annum. The EFH Corp. Toggle Notes mature in November 2017, with interest payable semiannually in arrears on May 1 and November 1 at a fixed rate of 11.250% per annum for cash interest and at a fixed rate of 12.000% per annum for PIK Interest. For any interest period until November 1, 2012, EFH Corp. may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFH Corp. Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. Once EFH Corp. makes a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. revokes the election.
The EFH Corp. 10.875% and Toggle Notes (collectively, the EFH Corp. Senior Notes) had a total principal amount as of December 31, 2010 of $930 million (excluding $3.724 billion principal amount held by EFIH) and are fully and unconditionally guaranteed on a joint and several unsecured basis by EFCH and EFIH.
EFH Corp. may redeem these notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the related indenture. EFH Corp. may also redeem these notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFH Corp., EFH Corp. must offer to repurchase the EFH Corp. Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
The indenture also contains customary events of default, including, among others, failure to pay principal or interest on the notes or the guarantees when due. If an event of default occurs under the indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes may declare the principal amount on the notes to be due and payable immediately.
EFH Corp. 9.75% Notes and EFIH 9.75% Notes —The EFH Corp. 9.75% Notes and EFIH 9.75% Notes mature in October 2019, with interest payable in cash semi-annually in arrears on April 15 and October 15 at a fixed rate of 9.75% per annum. The EFH Corp. 9.75% Notes are fully and unconditionally guaranteed on a joint and several basis by EFCH and EFIH. The guarantee from EFIH is secured by the pledge of the EFIH Collateral. The guarantee from EFCH is not secured. The EFIH 9.75% Notes are secured by the EFIH Collateral on an equal and ratable basis with the EFIH 10% Notes and EFIH’s guarantee of the EFH Corp. 10% Notes and the EFH Corp. 9.75% Notes.
As of December 31, 2010, there were $115 million and $141 million total principal amount of EFH Corp. 9.75% Notes and EFIH 9.75% Notes, respectively. The EFH Corp. 9.75% Notes and EFIH 9.75% Notes are senior obligations of each issuer and rank equally in right of payment with all senior indebtedness of each issuer and are senior in right of payment to any future subordinated indebtedness of each issuer. The EFH Corp. 9.75% Notes are effectively subordinated to any indebtedness of EFH Corp. secured by assets of EFH Corp. to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other liabilities of EFH Corp.’s non-guarantor subsidiaries. The EFIH 9.75% Notes are effectively senior to all unsecured indebtedness of EFIH, to the extent of the value of the EFIH Collateral, and will be effectively subordinated to any indebtedness of EFIH secured by assets of EFIH other than the EFIH Collateral, to the extent of the value of the assets securing such indebtedness. Furthermore, the EFIH 9.75% Notes will be structurally subordinated to all indebtedness and other liabilities of EFIH’s subsidiaries (other than EFIH Finance), including Oncor Holdings and its subsidiaries.
The guarantees of the EFH Corp. 9.75% Notes are the general senior obligations of each guarantor and rank equally in right of payment with all existing and future senior indebtedness of each guarantor. The guarantee from EFIH is effectively senior to all unsecured indebtedness of EFIH to the extent of the value of the EFIH Collateral. The guarantee will be effectively subordinated to all secured indebtedness of each guarantor secured by assets other than the EFIH Collateral to the extent of the value of the assets securing such indebtedness and will be structurally subordinated to any existing and future indebtedness and liabilities of EFH Corp.’s subsidiaries that are not guarantors.
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The indentures for the EFH Corp. 9.75% Notes and EFIH 9.75% Notes contain a number of covenants that, among other things, restrict, subject to certain exceptions, the issuers’ and their restricted subsidiaries’ ability to:
| • | make restricted payments; |
| • | incur debt and issue preferred stock; |
| • | create liens; |
| • | enter into mergers or consolidations; |
| • | sell or otherwise dispose of certain assets, and |
| • | engage in certain transactions with affiliates. |
The indentures also contain customary events of default, including, among others, failure to pay principal or interest on the notes or the guarantees when due. If certain events of default occur and are continuing under a series of notes and the related indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes of such series may declare the principal amount of the notes of such series to be due and payable immediately.
There currently are no restricted subsidiaries under the indenture related to the EFIH 9.75% Notes (other than EFIH Finance, which has no assets). Oncor Holdings, the immediate parent of Oncor, and its subsidiaries are unrestricted subsidiaries under the EFIH indenture and, accordingly, are not subject to any of the restrictive covenants in the indenture.
The respective issuers may redeem the EFH Corp. 9.75% Notes and EFIH 9.75% Notes, in whole or in part, at any time on or after October 15, 2014, at specified redemption prices, plus accrued and unpaid interest, if any. In addition, before October 15, 2012, the respective issuers may redeem up to 35% of the aggregate principal amount of each series of the notes from time to time at a redemption price of 109.750% of the aggregate principal amount of such series of notes, plus accrued and unpaid interest, if any, with the net cash proceeds of certain equity offerings. The respective issuers may also redeem each series of the notes at any time prior to October 15, 2014 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. Upon the occurrence of a change of control (as described in the indenture), the respective issuers may be required to offer to repurchase each series of the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
EFIH 10% Notes — The EFIH 10% Notes mature in December 2020, with interest payable in cash semi-annually in arrears on June 1 and December 1 at a fixed rate of 10% per annum. The EFIH 10% Notes are secured by the EFIH Collateral. The EFIH 10% Notes are secured on an equal and ratable basis with the EFIH 9.75% Notes and EFIH’s guarantee of the EFH Corp. Senior Secured Notes.
As of December 31, 2010, there were $2.180 billion total principal amount of EFIH 10% Notes. The EFIH 10% Notes are senior obligations of EFIH and rank equally in right of payment with all existing and future senior indebtedness of EFIH (including the EFIH 9.75% Notes and EFIH’s guarantees of the EFH Corp. Senior Secured Notes). The EFIH 10% Notes are effectively senior to all unsecured indebtedness of EFIH, to the extent of the value of the EFIH Collateral, and are effectively subordinated to any indebtedness of EFIH secured by assets of EFIH other than the EFIH Collateral, to the extent of the value of the assets securing such indebtedness. Furthermore, the EFIH 10% Notes are (i) structurally subordinated to all indebtedness and other liabilities of EFIH’s subsidiaries (other than EFIH Finance), including Oncor Holdings and its subsidiaries, any of EFIH’s future foreign subsidiaries and any other unrestricted subsidiaries and (ii) senior in right of payment to any future subordinated indebtedness of the Issuers.
The indenture for the EFIH 10% Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, EFIH’s and its restricted subsidiaries’ ability to:
| • | make restricted payments; |
| • | incur debt and issue preferred stock; |
| • | create liens; |
| • | enter into mergers or consolidations; |
| • | sell or otherwise dispose of certain assets, and |
| • | engage in certain transactions with affiliates. |
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The indenture also contains customary events of default, including, among others, failure to pay principal or interest on the notes or the guarantees when due. If certain events of default occur and are continuing under the notes and the indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes may declare the principal amount of the notes to be due and payable immediately. Currently, there are no restricted subsidiaries under the indenture (other than EFIH Finance, which has no assets). Oncor Holdings, Oncor and their respective subsidiaries are unrestricted subsidiaries under the EFIH 10% Notes and the indenture and, accordingly, are not subject to any of the restrictive covenants in the notes and the related indenture.
Until December 1, 2013, EFIH may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the EFIH 10% Notes from time to time at a redemption price of 110% of the aggregate principal amount of the notes being redeemed, plus accrued and unpaid interest, if any. EFIH may redeem the EFIH 10% Notes, in whole or in part, at any time prior to December 1, 2015 at a price equal to 100% of their principal amount, plus accrued and unpaid interest, if any, and the applicable premium as defined in the indenture. EFIH may redeem any of the EFIH 10% Notes, in whole or in part, at any time on or after December 1, 2015, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control (as defined in the indenture), EFIH may be required to offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
Intercreditor Agreement — In October 2007, TCEH entered into an intercreditor agreement with Citibank, N.A. and five secured commodity hedge counterparties (the Secured Commodity Hedge Counterparties). In connection with the August 2009 amendment to the TCEH Secured Facilities described above, the intercreditor agreement was amended and restated (as amended and restated, the Intercreditor Agreement) to take into account, among other things, the possibility that TCEH could issue notes and/or loans secured by collateral (other than the collateral that secures the TCEH Senior Secured Facilities) that ranks on parity with, or junior to, TCEH’s existing first lien obligations under the TCEH Senior Secured Facilities. The Intercreditor Agreement provides that the lien granted to the Secured Commodity Hedge Counterparties will rank pari passu with the lien granted with respect to the collateral of the secured parties under the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will be entitled to share, on a pro rata basis, in the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateral in an amount provided in the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will have voting rights with respect to any amendment or waiver of any provision of the Intercreditor Agreement that changes the priority of the Secured Commodity Hedge Counterparties’ lien on such collateral relative to the priority of lien granted to the secured parties under the TCEH Senior Secured Facilities or the priority of payments to the Secured Commodity Hedge Counterparties upon a foreclosure and liquidation of such collateral relative to the priority of the lien granted to the secured parties under the TCEH Senior Secured Facilities.
Second Lien Intercreditor Agreement — In October 2010, TCEH entered into a second lien intercreditor agreement (the Second Lien Intercreditor Agreement) with Citibank, N.A., as senior collateral agent, and The Bank of New York Mellon Trust Company, N.A., as initial second priority representative. The Second Lien Intercreditor Agreement provides that liens on the collateral that secure the obligations under the TCEH Senior Secured Facilities, the obligations of the Secured Commodity Hedge Counterparties and any other obligations which are permitted to be secured on a pari passu basis therewith (collectively, the First Lien Obligations) will rank prior to the liens on such collateral securing the obligations under the TCEH Senior Secured Second Lien Notes, and any other obligations which are permitted to be secured on a pari passu basis (collectively, the Second Lien Obligations). The Second Lien Intercreditor Agreement provides that the holders of the First Lien Obligations will be entitled to the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateral until paid in full, and that the holders of the Second Lien Obligations will not be entitled to receive any such proceeds until the First Lien Obligations have been paid in full. The Second Lien Intercreditor Agreement also provides that the holders of the First Lien Obligations will control enforcement actions with respect to such collateral, and the holders of the Second Lien Obligations will not be entitled to commence any such enforcement actions, with limited exceptions. The Second Lien Intercreditor Agreement also provides that releases of the liens on the collateral by the holders of the First Lien Obligations will automatically require that the liens on such collateral by the holders of the Second Lien Obligations be automatically released, and that amendments, waivers or consents with respect to any of the collateral documents in connection with the First Lien Obligations apply automatically to any comparable provision of the collateral documents in connection with the Second Lien Obligations.
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TCEH Interest Rate Swap Transactions—As of December 31, 2010, TCEH has entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $15.80 billion principal amount of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.3% and 8.3% on debt maturing from 2011 to 2014. Swaps related to an aggregate $500 million principal amount of debt expired in 2010, and no interest rate swap transactions were entered into in 2010. Interest rate swaps on an aggregate of $15.05 billion were being accounted for as cash flow hedges related to variable interest rate cash flows until August 29, 2008, at which time these swaps were dedesignated as cash flow hedges as a result of the intent to change the variable interest rate terms of the hedged debt (from three-month LIBOR to one-month LIBOR) in connection with the planned execution of interest rate basis swaps (discussed immediately below) to further reduce the fixed borrowing costs. Based on the fair value of the positions, the cumulative unrealized mark-to-market net losses related to these interest rate swaps totaled $431 million (pre-tax) at the dedesignation date and was recorded in accumulated other comprehensive income. This balance is being reclassified into net income as interest on the hedged debt is reflected in net income.
As of December 31, 2010, TCEH has entered into interest rate basis swap transactions pursuant to which payments at floating interest rates of three-month LIBOR on an aggregate of $15.20 billion principal amount of senior secured term loans of TCEH were exchanged for floating interest rates of one-month LIBOR plus spreads ranging from 0.0625% to 0.2055%. These transactions include swaps entered into in the year ended December 31, 2010 related to an aggregate $2.55 billion principal amount of TCEH senior secured term loans. Swaps related to an aggregate $3.60 billion principal amount of TCEH senior secured term loans expired in 2010.
The interest rate swap counterparties are proportionately secured by the same collateral package granted to the lenders under the TCEH Senior Secured Facilities. Changes in the fair value of such swaps are being reported in the income statement in interest expense and related charges, and such unrealized mark-to-market value changes totaled $207 million in net losses in the year ended December 31, 2010 and $696 million in net gains in the year ended December 31, 2009. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.419 billion as of December 31, 2010, of which $105 million (pre-tax) was reported in accumulated other comprehensive income.
See Note 17 for discussion of collateral investments in 2009 related to certain of these interest rate swaps.
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| 12. | COMMITMENTS AND CONTINGENCIES |
Contractual Commitments
As of December 31, 2010, we had noncancellable commitments under energy-related contracts, leases and other agreements as follows:
| Coal purchase agreements and coal transportation agreements | Pipeline transportation and storage reservation fees | Capacity payments under power purchase agreements (a) | Nuclear Fuel Contracts | Water Rights Contracts | ||||||||||||||||
2011 | $ | 473 | $ | 35 | $ | 63 | $ | 183 | $ | 9 | ||||||||||
2012 | 366 | 28 | 3 | 195 | 9 | |||||||||||||||
2013 | 334 | — | — | 123 | 8 | |||||||||||||||
2014 | 306 | — | — | 114 | 8 | |||||||||||||||
2015 | — | — | — | 164 | 8 | |||||||||||||||
Thereafter | — | — | — | 736 | 56 | |||||||||||||||
Total | $ | 1,479 | $ | 63 | $ | 66 | $ | 1,515 | $ | 98 | ||||||||||
| (a) | On the basis of current expectations of demand from electricity customers as compared with capacity and take-or-pay payments, management does not consider it likely that any material payments will become due for electricity not taken beyond capacity payments. |
Expenditures under our coal purchase and coal transportation agreements totaled $445 million, $316 million and $268 million for the years ended December 31, 2010, 2009 and 2008, respectively.
As of December 31, 2010, future minimum lease payments under both capital leases and operating leases are as follows:
| Capital Leases | Operating Leases (a) | |||||||
2011 | $ | 21 | $ | 48 | ||||
2012 | 18 | 47 | ||||||
2013 | 12 | 47 | ||||||
2014 | 7 | 43 | ||||||
2015 | 5 | 41 | ||||||
Thereafter | 38 | 237 | ||||||
Total future minimum lease payments | 101 | $ | 463 | |||||
Less amounts representing interest | 21 | |||||||
Present value of future minimum lease payments | 80 | |||||||
Less current portion | 17 | |||||||
Long-term capital lease obligation | $ | 63 | ||||||
| ||||||||
| (a) | Includes operating leases with initial or remaining noncancellable lease terms in excess of one year. |
Rent reported as operating costs, fuel costs and SG&A expenses totaled $89 million for the year ended December 31, 2010 and $92 million for each of the years ended December 31, 2009 and 2008.
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Commitment to Fund Demand Side Management Initiatives
In connection with the Merger, Texas Holdings committed to spend $100 million over the five-year period ending December 31, 2012 on demand side management or other energy efficiency initiatives. As of December 31, 2010, we had spent 39% of this commitment. This commitment is expected to be funded by EFH Corp. and/or its subsidiaries other than Oncor. This commitment is in addition to over $300 million to be invested by Oncor for similar initiatives. See Note 6 for other provisions of the stipulation, including a similar commitment made by Oncor.
Guarantees
We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. Material guarantees are discussed below.
Disposed TXU Gas operations —In connection with the sale of TXU Gas in October 2004, EFH Corp. agreed to indemnify Atmos Energy Corporation (Atmos), until October 1, 2014, for up to $500 million for any liability related to assets retained by TXU Gas, including certain inactive gas plant sites not acquired by Atmos, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximum aggregate amount under these indemnities that we may be required to pay is $1.9 billion. To date, we have not been required to make any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.
Residual value guarantees in operating leases — We are the lessee under various operating leases that guarantee the residual values of the leased assets. As of December 31, 2010, the aggregate maximum amount of residual values guaranteed was $13 million with an estimated residual recovery of $13 million. These leased assets consist primarily of rail cars. The average life of the residual value guarantees under the lease portfolio is approximately six years.
See Note 11 for discussion of guarantees and security for certain of our debt.
Letters of Credit
As of December 31, 2010, TCEH had outstanding letters of credit under its credit facilities totaling $874 million as follows:
| • | $473 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions and collateral postings with ERCOT; |
| • | $208 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $204 million (the letters of credit are available to fund the payment of such debt obligations and expire in 2014); |
| • | $73 million to support TCEH’s REP financial requirements with the PUCT, and |
| • | $120 million for miscellaneous credit support requirements. |
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Litigation Related to Generation Facilities
In November 2010, an administrative appeal challenging the decision of the TCEQ to renew and amend Oak Grove Management Company LLC’s (Oak Grove) (a wholly-owned subsidiary of TCEH) Texas Pollutant Discharge Elimination System (TPDES) permit related to water discharges was filed by Robertson County: Our Land, Our Lives and Roy Henrichson in the Travis County, Texas District Court. Plaintiffs seek a reversal of the TCEQ’s order and a remand back to the TCEQ for further proceedings. In addition to this administrative appeal, in November 2010, two other petitions were filed in Travis County, Texas District Court by Sustainable Energy and Economic Development Coalition and Paul and Lisa Rolke, respectively, who were non-parties to the administrative hearing before the State Office of Administrative Hearings, challenging the TCEQ’s decision to renew and amend Oak Grove’s TPDES permit and asking the District Court to remand the matter to the TCEQ for further proceedings. Although 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 financial condition, results of operations or liquidity.
In September 2010, the Sierra Club filed a lawsuit in the US District Court for the Eastern District of Texas (Texarkana Division) against EFH Corp. and Luminant Generation Company LLC (a wholly-owned subsidiary of TCEH) for alleged violations of the Clean Air Act at Luminant’s Martin Lake generation facility. While we are unable to estimate any possible loss or predict the outcome of the litigation, we believe that the Sierra Club’s claims are without merit, and we intend to vigorously defend this litigation. In addition, in February 2010, the Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Big Brown generation facility. Subsequently, in December 2010, Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Monticello generation facility. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.
Regulatory Reviews
In June 2008, the EPA issued a request for information to TCEH under the EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.
Other Proceedings
In addition to the above, we are involved in various other legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on our financial condition, results of operations or liquidity.
Labor Contracts
Certain personnel engaged in TCEH activities are represented by labor unions and covered by collective bargaining agreements with varying expiration dates. In November 2010, new one-year labor agreements were reached covering bargaining unit personnel engaged in lignite-fueled generation operations (excluding Sandow), lignite mining operations (excluding Three Oaks) and natural gas-fueled generation operations. In October 2010, new two-year labor agreements were reached covering bargaining unit personnel engaged in the Sandow lignite-fueled generation operations and the Three Oaks lignite mining operations. In August 2010, a new three-year labor agreement was reached covering bargaining unit personnel engaged in nuclear-fueled generation operations. We do not expect any changes in collective bargaining agreements to have a material effect on our results of operations, liquidity or financial condition.
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Environmental Contingencies
The federal Clean Air Act, as amended (Clean Air Act) includes provisions which, among other things, place limits on SO2 and NOx emissions produced by electricity generation plants. The capital requirements of the company have not been significantly affected by the requirements of the Clean Air Act. In addition, all air pollution control provisions of the 1999 Restructuring Legislation have been satisfied.
We must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. We believe that we are in compliance with current environmental laws and regulations; however, the impact, if any, of changes to existing regulations or the implementation of new regulations is not determinable and could materially and adversely affect our financial condition, results of operations and liquidity.
The costs to comply with environmental regulations can be significantly affected by the following external events or conditions:
| • | enactment of state or federal regulations regarding CO2 and other greenhouse gas emissions; |
| • | other changes to existing state or federal regulation regarding air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters, including revisions to CAIR currently being developed by the EPA as a result of court rulings discussed in Note 4 and revisions to the federal Clean Air Mercury Rule (CAMR) also being developed by the EPA as a result of similar court rulings, and |
| • | the identification of sites requiring clean-up or the filing of other complaints in which we may be asserted to be potential responsible parties. |
Nuclear Insurance
Nuclear insurance includes liability coverage, property damage, decontamination and premature decommissioning coverage and accidental outage and/or extra expense coverage. The liability coverage is governed by the Price-Anderson Act (Act), while the property damage, decontamination and premature decommissioning coverage are promulgated by the rules and regulations of the NRC. We intend to maintain insurance against nuclear risks as long as such insurance is available. The company is self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Such losses could have a material adverse effect on our financial condition and results of operations and liquidity.
With regard to liability coverage, the Act provides financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $12.5 billion and requires nuclear generation plant operators to provide financial protection for this amount. The US Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $12.5 billion limit for a single incident mandated by the Act. As required, the company provides this financial protection for a nuclear incident at Comanche Peak resulting in public bodily injury and property damage through a combination of private insurance and industry-wide retrospective payment plans. As the first layer of financial protection, the company has $375 million of liability insurance from American Nuclear Insurers (ANI), which provides such insurance on behalf of a major stock insurance company pool, Nuclear Energy Liability Insurance Association. The second layer of financial protection is provided under an industry-wide retrospective payment program called Secondary Financial Protection (SFP).
Under the SFP, in the event of an incident at any nuclear generation plant in the US, each operating licensed reactor in the US is subject to an assessment of up to $117.5 million plus a 3% insurance premium tax, subject to increases for inflation every five years. Assessments are limited to $17.5 million per operating licensed reactor per year per incident. The company’s maximum potential assessment under the industry retrospective plan would be $235 million (excluding taxes) per incident but no more than $35 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $375 million per accident at any nuclear facility. The SFP and liability coverage are not subject to any deductibles.
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With respect to nuclear decontamination and property damage insurance, the NRC requires that nuclear generation plant license-holders maintain at least $1.06 billion of such insurance and require the proceeds thereof to be used to place a plant in a safe and stable condition, to decontaminate it pursuant to a plan submitted to and approved by the NRC before the proceeds can be used for plant repair or restoration or to provide for premature decommissioning. The company maintains nuclear decontamination and property damage insurance for Comanche Peak in the amount of $2.25 billion (subject to $5 million deductible per accident), above which the company is self-insured. This insurance coverage consists of a primary layer of coverage of $500 million provided by Nuclear Electric Insurance Limited (NEIL), a nuclear electric utility industry mutual insurance company and $1.40 billion of premature decommissioning coverage also provided by NEIL. The European Mutual Association for Nuclear Insurance provides additional insurance limits of $350 million in excess of NEIL’s $1.9 billion coverage.
The company maintains Accidental Outage Insurance through NEIL to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at Comanche Peak are out of service for more than twelve weeks as a result of covered direct physical damage. The coverage provides for weekly payments of $3.5 million for the first fifty-two weeks and $2.8 million for the next 110 weeks for each outage, respectively, after the initial twelve-week waiting period. The total maximum coverage is $490 million per unit. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident.
If NEIL’s losses exceeded its reserves for the applicable coverage, potential assessments in the form of a retrospective premium call could be made up to ten times annual premiums. The company maintains insurance coverage against these potential retrospective premium calls.
Also, under the NEIL policies, if there were multiple terrorism losses occurring within a one-year time frame, NEIL would make available one industry aggregate limit of $3.2 billion plus any amounts it recovers from other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply.
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| 13. | SHAREHOLDERS’ EQUITY |
Equity Issuances and Repurchases
In the year ended December 31, 2008, EFH Corp. issued an aggregate of approximately 5.5 million shares of its common stock to, or for the benefit of, certain of its officers, directors and employees for an aggregate consideration of $27.4 million, which included shares previously subscribed. In addition, in the years ended December 31, 2010, 2009 and 2008, EFH Corp. issued an aggregate of 3.9 million, 1.5 million and 1.7 million shares, respectively, of its common stock to, or for the benefit of, certain officers, directors and employees as stock-based compensation as discussed in Note 21. The 2010 issuances included 1.2 million shares of previously issued restricted or deferred stock units that vested in 2010. In 2008, EFH Corp. repurchased 0.8 million shares of its common stock from employees primarily upon termination of employment or amendment of agreements, for an aggregate consideration of $3.9 million.
Effect of Sale of Noncontrolling Interests
The total amount of proceeds from the sale of noncontrolling interests in Oncor discussed in Note 14 was less than the carrying value of the interests sold by $265 million, which reflects the fact that Oncor’s carrying value after purchase accounting is based on the Merger value, while the noncontrolling interests sale value does not include a control premium. This difference was accounted for as a reduction of additional paid-in capital.
As a result of the sale of the noncontrolling interests and the application of rules for income tax accounting related to outside basis differences, activity in 2008 reflects an increase in the balance of noncurrent accumulated deferred income tax liabilities of $141 million and a decrease in additional paid-in capital by the same amount.
Dividend Restrictions
The indentures governing the EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes include covenants that, among other things and subject to certain exceptions, restrict our ability to pay dividends or make other distributions in respect of our common stock. Accordingly, essentially all of our net income is restricted from being used to make distributions on our common stock unless such distributions are expressly permitted under these indentures and/or on a pro forma basis, after giving effect to such distribution, EFH Corp.’s consolidated leverage ratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, “consolidated leverage ratio” is defined as the ratio of consolidated total debt (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiaries other than Oncor Holdings and its subsidiaries. EFH Corp.’s consolidated leverage ratio was 8.5 to 1.0 as of December 31, 2010.
In addition, the indentures governing the EFIH Notes generally restrict EFIH from making any cash distribution to EFH Corp. for the ultimate purpose of making a cash dividend on our common stock unless at the time, and after giving effect to such dividend, EFIH’s consolidated leverage ratio is equal to or less than 6.0 to 1.0. Under the indentures governing the EFIH Notes, the term “consolidated leverage ratio” is defined as the ratio of EFIH’s consolidated total debt (as defined in the indentures) to EFIH’s Adjusted EBITDA on a consolidated basis (including Oncor’s Adjusted EBITDA). EFIH’s consolidated leverage ratio was 5.3 to 1.0 as of December 31, 2010.
The TCEH Senior Secured Facilities generally restrict TCEH from making any cash distribution to any of its parent companies for the ultimate purpose of making a cash dividend on our common stock unless at the time, and after giving effect to such dividend, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. As of December 31, 2010, that ratio was 7.9 to 1.0.
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In addition, the TCEH Senior Secured Facilities and indentures governing the TCEH Senior Notes and TCEH Senior Secured Second Lien Notes generally restrict TCEH’s ability to make distributions or loans to any of its parent companies, EFCH and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes and TCEH Senior Secured Second Lien Notes. Those agreements generally permit TCEH to make unlimited distributions or loans to its parent companies for corporate overhead costs, SG&A expenses, taxes and principal and interest payments. In addition, those agreements contain certain investment and dividend baskets that would allow TCEH to make additional distributions and/or loans to its parent companies up to the amount of such baskets. As of December 31, 2010 and 2009, EFH Corp. demand notes payable to TCEH totaled $1.921 billion and $1.406 billion, respectively, of which $916 million and $416 million, respectively, was related to principal and interest payments. Such principal and interest amounts are guaranteed by EFCH and EFIH on a pari passu basis with their guarantees of the EFH Corp. Senior Notes; the remaining balance of the demand notes is not guaranteed.
In addition, under applicable law, we would be prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent.
EFH Corp. did not declare or pay any dividends in 2010, 2009 or 2008.
Distributions from Oncor —Until December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor’s net income determined in accordance with GAAP, subject to certain defined adjustments. Such adjustments include deducting the $72 million ($46 million after-tax) one-time refund to customers in September 2008, net accretion of fair value adjustments resulting from purchase accounting and funds spent as part of the $100 million commitment for additional demand-side management or other energy efficiency initiatives (see Note 6) of which $46 million ($30 million after tax) has been spent through December 31, 2010, and removing the effects of the $860 million goodwill impairment charge from fourth quarter 2008 net income available for distribution. As of December 31, 2010, $140 million was available for distribution to Oncor’s members under the cumulative net income restriction, of which approximately 80% relates to EFH Corp.’s ownership interest.
Oncor’s distributions are further limited by an agreement with the PUCT that its regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. As of December 31, 2010, the regulatory capitalization ratio was 59.7% debt and 40.3% equity. The PUCT has the authority to determine what types of debt and equity are included in a utility’s debt-to-equity ratio. For purposes of this ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. The debt calculation excludes transition bonds issued by Oncor Electric Delivery Transition Bond Company. Equity is calculated as membership interests determined in accordance with GAAP, excluding the effects of accounting for the Merger (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization). As of December 31, 2010, $44 million was available for distribution under the capital structure restriction, of which approximately 80% relates to EFH Corp.’s ownership interest. In January 2011, Oncor filed for a rate review with the PUCT and 203 cities that, among other things, requested a revised regulatory capital structure of 55% debt to 45% equity, which if approved as requested, would further limit distributions from Oncor.
Shareholder Actions
In May 2009, the shareholders of EFH Corp. approved the change of the stated capital of EFH Corp.’s common stock, no par value per share, to an amount equal to $0.001 for each outstanding share of common stock, resulting in total stated value of outstanding common stock of $2 million. Also in May 2009, EFH Corp.’s board of directors approved a decrease in additional paid-in capital of the same amount and the allocation of $0.001 per share to stated value of common stock upon issuance of any authorized but unissued shares of common stock that may occur from time to time, with the remainder of any amounts received for such shares allocated to additional paid-in capital.
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Common Stock Registration Rights
The Sponsor Group and certain other investors entered into a registration rights agreement with EFH Corp. upon closing of the Merger. Pursuant to this agreement, in certain instances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.’s common stock owned directly or indirectly by them under the Securities Act. In certain instances, the Sponsor Group and certain other investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.’s common stock under the Securities Act that it may undertake.
See Note 21 for discussion of stock-based compensation plans.
| 14. | NONCONTROLLING INTERESTS |
In November 2008, equity interests in Oncor were sold to Texas Transmission for $1.254 billion in cash. Equity interests were also indirectly sold to certain members of Oncor’s board of directors and its management team. Accordingly, after giving effect to all equity issuances, as of December 31, 2010, ownership of Oncor’s membership interests was as follows: 80.03% held indirectly by EFH Corp., 0.22% held indirectly by Oncor’s management and board of directors and 19.75% held by Texas Transmission.
The proceeds (net of closing costs) of $1.253 billion received by Oncor from Texas Transmission and the members of Oncor management upon completion of these transactions were distributed ultimately to EFH Corp. Under the terms of certain financing arrangements of EFH Corp. and TCEH, upon such distribution, under certain circumstances, EFH Corp. (parent entity) was required to repay certain outstanding intercompany loans from TCEH. In November 2008, EFH Corp. repaid the $253 million balance of notes payable to TCEH that related to payments of principal and interest on EFH Corp. (parent entity) debt.
See Note 13 for discussion of amounts recorded as a reduction of shareholders’ equity as a result of the sale of Oncor interests.
Of the noncontrolling interests balance reported in the December 31, 2009 consolidated balance sheet, $1.363 billion related to Oncor. The noncontrolling interests balance reported in the December 31, 2009 consolidated balance sheet represented the proportional share of Oncor’s net assets at the date of the transaction less $96 million representing the noncontrolling interests’ share of Oncor’s net losses for the periods subsequent to the transaction (including the goodwill impairment charge), net of $58 million in cash distributions. See Notes 1 and 3 for discussion of the deconsolidation of Oncor in 2010.
In connection with the filing of a combined operating license application with the NRC for two new nuclear generation units, in January 2009, TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, CPNPC, to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. Under the terms of the joint venture agreement, a subsidiary of TCEH owns an 88% interest in the venture and a subsidiary of MHI owns a 12% interest. This joint venture is a variable interest entity, and a subsidiary of TCEH is considered the primary beneficiary (see Note 3).
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| 15. | FAIR VALUE MEASUREMENTS |
Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a “mid-market” valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.
We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:
| • | Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities include exchange traded commodity contracts. For example, a significant number of our derivatives are NYMEX futures and swaps transacted through clearing brokers for which prices are actively quoted. |
| • | Level 2 valuations use inputs, in the absence of actively quoted market prices, that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means and other valuation inputs. For example, our Level 2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes are available. |
| • | Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assets and liabilities include certain derivatives whose values are derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means. |
We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.
In utilizing broker quotes, we attempt to obtain multiple quotes from brokers that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker’s publication policy, recent trading volume trends and various other factors. In addition, for valuation of interest rate swaps, we use a combination of dealer provided market valuations (generally non-binding) and Bloomberg valuations based on month-end interest rate curves and standard rate swap valuation models.
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Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including commodity prices, volatility factors, discount rates and other inputs. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Those valuation models are generally used in developing long-term forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.
With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.
As of December 31, 2010, assets and liabilities measured at fair value on a recurring basis consisted of the following:
| Level 1 | Level 2 | Level 3 (a) | Reclassification(b) | Total | ||||||||||||||||
Assets: | ||||||||||||||||||||
Commodity contracts | $ | 727 | $ | 3,575 | $ | 401 | $ | 2 | $ | 4,705 | ||||||||||
Interest rate swaps | — | 98 | — | — | 98 | |||||||||||||||
Nuclear decommissioning trust – | 192 | 121 | — | — | 313 | |||||||||||||||
Nuclear decommissioning trust – | — | 223 | — | — | 223 | |||||||||||||||
Total assets | $ | 919 | $ | 4,017 | $ | 401 | $ | 2 | $ | 5,339 | ||||||||||
Liabilities: | ||||||||||||||||||||
Commodity contracts | $ | 875 | $ | 672 | $ | 59 | $ | 2 | $ | 1,608 | ||||||||||
Interest rate swaps | — | 1,544 | — | — | 1,544 | |||||||||||||||
Total liabilities | $ | 875 | $ | 2,216 | $ | 59 | $ | 2 | $ | 3,152 | ||||||||||
| (a) | Level 3 assets and liabilities consist primarily of a complex wind generation purchase contract, certain natural gas positions (collars) in the long-term hedging program and certain power transactions valued at illiquid pricing locations as discussed below. |
| (b) | Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities. |
| (c) | The nuclear decommissioning trust investment is included in the other investments line on the balance sheet. See Note 18. |
See Note 20 for fair value measurements related to pension and OPEB plan assets.
In conjunction with ERCOT’s transition to a nodal wholesale market structure effective December 2010, we have entered (and expect to increasingly enter) into certain derivative transactions that are valued at illiquid pricing locations (unobservable inputs), thus requiring classification as Level 3 assets or liabilities. As the nodal market matures and more transactions and pricing information becomes available for these pricing locations, we expect more of the valuation inputs to become observable.
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As of December 31, 2009, assets and liabilities measured at fair value on a recurring basis consisted of the following:
| Level 1 | Level 2 | Level 3 (a) | Reclassification(b) | Total | ||||||||||||||||
Assets: | ||||||||||||||||||||
Commodity contracts | $ | 918 | $ | 2,588 | $ | 350 | $ | 4 | $ | 3,860 | ||||||||||
Interest rate swaps | — | 64 | — | — | 64 | |||||||||||||||
Nuclear decommissioning trust – equity securities (c) | 154 | 105 | — | | — | | 259 | |||||||||||||
Nuclear decommissioning trust – debt securities (c) | — | 216 | — | — | 216 | |||||||||||||||
Total assets | $ | 1,072 | $ | 2,973 | $ | 350 | $ | 4 | $ | 4,399 | ||||||||||
Liabilities: | ||||||||||||||||||||
Commodity contracts | $ | 1,077 | $ | 796 | $ | 269 | $ | 4 | $ | 2,146 | ||||||||||
Interest rate swaps | — | 1,306 | — | — | 1,306 | |||||||||||||||
Total liabilities | $ | 1,077 | $ | 2,102 | $ | 269 | $ | 4 | $ | 3,452 | ||||||||||
| (a) | Level 3 assets and liabilities consist primarily of complex long-term power purchase and sales agreements, including a long-term wind generation purchase contract and certain natural gas positions (collars) in the long-term hedging program. |
| (b) | Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities. |
| (c) | The nuclear decommissioning trust investment is included in the other investments line on the balance sheet. See Note 18. |
Commodity contracts consist primarily of natural gas, electricity, fuel oil and coal derivative instruments entered into for hedging purposes and include physical contracts that have not been designated “normal” purchases or sales. See Note 17 for further discussion regarding the company’s use of derivative instruments.
Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 11 for discussion of interest rate swaps.
Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.
There were no significant transfers between the levels of the fair value hierarchy for the year ended December 31, 2010.
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The following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts) for the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Balance as of beginning of period | $ | 81 | $ | (72 | ) | $ | (173 | ) | ||||
Total realized and unrealized gains (losses) (a): | ||||||||||||
Included in net income (loss) | 266 | 115 | (5 | ) | ||||||||
Included in other comprehensive income (loss) | — | (30 | ) | — | ||||||||
Purchases, sales, issuances and settlements (net) (b) | 26 | 51 | (13 | ) | ||||||||
Transfers into Level 3 (c) | (12 | ) | 2 | 70 | ||||||||
Transfers out of Level 3 (c) | (19 | ) | 15 | 49 | ||||||||
Balance as of end of period | $ | 342 | $ | 81 | $ | (72 | ) | |||||
Net change in unrealized gains (losses) included in net income relating to instruments held as of end of period | $ | 111 | $ | 105 | $ | 87 | ||||||
| (a) | In 2008 and 2009, substantially all changes in values of commodity contracts are reported in the income statement in net gain from commodity hedging and trading activities. In 2010, net gains of $150 million are reported in net gain from commodity hedging and trading activities, and a gain of $116 million on the termination of a long-term power sales contract is reported in other income in the income statement. |
| (b) | Settlements represent reversals of unrealized mark-to-market valuations of these positions previously recognized in net income. Purchases and issuances reflect option premiums paid or received. |
| (c) | Includes transfers due to changes in the observability of significant inputs. For 2010, in accordance with new accounting guidance issued by the FASB in January 2010, transfers in and out occur at the end of each quarter, which is when the assessments are performed. Prior period transfers in were assumed to transfer in at the beginning of the quarter and transfers out at the end of the quarter. |
| 16. | FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS |
The carrying amounts and related estimated fair values of significant nonderivative financial instruments as of December 31, 2010 and 2009 were as follows:
| December 31, 2010 | December 31, 2009 | |||||||||||||||
| Carrying Amount | Fair Value (a) | Carrying Amount | Fair Value (a) | |||||||||||||
On balance sheet liabilities: | ||||||||||||||||
Long-term debt (including current maturities) (b): | ||||||||||||||||
TCEH, EFH Corp., and other | $ | 34,815 | $ | 26,594 | $ | 36,600 | $ | 29,115 | ||||||||
Oncor (c) | $ | — | $ | — | $ | 5,104 | $ | 5,644 | ||||||||
Total | $ | 34,815 | $ | 26,594 | $ | 41,704 | $ | 34,759 | ||||||||
Off balance sheet liabilities: | ||||||||||||||||
Financial guarantees | $ | — | $ | 9 | $ | — | $ | 6 | ||||||||
| (a) | Fair value determined in accordance with accounting standards related to the determination of fair value. |
| (b) | Excludes capital leases. |
| (c) | See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010. |
See Notes 15 and 17 for discussion of accounting for financial instruments that are derivatives.
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| 17. | COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES |
Strategic Use of Derivatives
We enter into physical and financial derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a long-term commodity hedging program and the hedging of interest costs on our long-term debt. See Note 15 for a discussion of the fair value of all derivatives.
Long-Term Hedging Program —TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity is largely correlated to the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas through 2014. These transactions are intended to hedge a majority of electricity price exposure related to expected baseload generation for this period. Changes in the fair value of the instruments under the long-term hedging program are reported in the income statement in net gain (loss) from commodity hedging and trading activities.
Interest Rate Swap Transactions — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to fixed rates, thereby hedging future interest costs and related cash flows. Interest rate basis swaps are used to effectively reduce the hedged borrowing costs. Changes in the fair value of the swaps are recorded as unrealized gains and losses in interest expense and related charges. See Note 11 for additional information about interest rate swap agreements.
Other Commodity Hedging and Trading Activity —In addition to the long-term hedging program, TCEH enters into derivatives, including electricity, natural gas, fuel oil and coal instruments, generally for shorter-term hedging purposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets.
Financial Statement Effects of Derivatives
Substantially all commodity and other derivative contractual assets and liabilities arise from mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of commodity and other derivative contractual assets and liabilities (with the column totals representing the net positions of the contracts) as reported in the balance sheets as of December 31, 2010 and 2009:
December 31, 2010 | ||||||||||||||||||||
| Derivative assets | Derivative liabilities | |||||||||||||||||||
| Commodity contracts | Interest rate swaps | Commodity contracts | Interest rate swaps | Total | ||||||||||||||||
Current assets | $ | 2,637 | $ | 95 | $ | — | $ | — | $ | 2,732 | ||||||||||
Noncurrent assets | 2,068 | 3 | — | — | 2,071 | |||||||||||||||
Current liabilities | (2 | ) | — | (1,542 | ) | (739 | ) | (2,283 | ) | |||||||||||
Noncurrent liabilities | — | — | (64 | ) | (805 | ) | (869 | ) | ||||||||||||
Net assets (liabilities) | $ | 4,703 | $ | 98 | $ | (1,606 | ) | $ | (1,544 | ) | $ | 1,651 | ||||||||
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December 31, 2009 | ||||||||||||||||||||
| Derivative assets | Derivative liabilities | |||||||||||||||||||
| Commodity contracts | Interest rate swaps | Commodity contracts | Interest rate swaps | Total | ||||||||||||||||
Current assets | $ | 2,327 | $ | 60 | $ | 4 | $ | — | $ | 2,391 | ||||||||||
Noncurrent assets | 1,529 | 4 | — | — | 1,533 | |||||||||||||||
Current liabilities | — | — | (1,705 | ) | (687 | ) | (2,392 | ) | ||||||||||||
Noncurrent liabilities | — | — | (441 | ) | (619 | ) | (1,060 | ) | ||||||||||||
Net assets (liabilities) | $ | 3,856 | $ | 64 | $ | (2,142 | ) | $ | (1,306 | ) | $ | 472 | ||||||||
As of December 31, 2010 and 2009, there were no derivative positions accounted for as cash flow or fair value hedges.
Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled $479 million and $358 million in net liabilities as of December 31, 2010 and 2009, respectively, which do not include the collateral investments related to certain interest rate swaps and commodity positions discussed immediately below. Reported amounts as presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positions with the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.
In 2009, we entered into collateral funding transactions with counterparties to certain interest rate swap agreements related to TCEH debt. Under the terms of these transactions, which we elected to enter into as a cash management measure, as of December 31, 2009, EFH Corp. (parent) had posted $400 million in cash and TCEH had posted $65 million in letters of credit to the counterparties, with the outstanding balance of such collateral earning interest. TCEH had also entered into commodity hedging transactions with one of these counterparties, and under an arrangement effective August 2009, both the interest rate swaps and certain of the commodity hedging transactions with the counterparty are under the same derivative agreement, which continues to be secured by a first-lien interest in the assets of TCEH. In accordance with the agreements, the counterparties returned the collateral, along with accrued interest, on March 31, 2010. As of December 31, 2009, the cash collateral was recorded as an investment and was presented in the balance sheet (including accrued interest) as a separate line item under current assets.
The following table presents the pre-tax effect on net income of derivatives not under hedge accounting, including realized and unrealized effects:
| Year Ended December 31, | ||||||||
Derivative (Income statement presentation) | 2010 | 2009 | ||||||
Commodity contracts (Net gain from commodity hedging and trading activities) | $ | 2,162 | $ | 1,741 | ||||
Commodity contracts (Other income) (a) | 116 | — | ||||||
Interest rate swaps (Interest expense and related charges) | (880 | ) | 12 | |||||
Net gain | $ | 1,398 | $ | 1,753 | ||||
| (a) | Represents a gain on termination of a long-term power sales contract (see Note 9). |
Amounts reported in the income statement in net gain from commodity hedging and trading activities include net “day one” mark-to-market gains of $5 million in the year ended December 31, 2010 and net “day one” mark-to-market losses of $2 million and $68 million in the years ended December 31, 2009 and 2008, respectively. Substantially all of these losses arose from a related series of derivative transactions entered into under the long-term hedging program.
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The following table presents the pre-tax effect on net income and other comprehensive income (OCI) of derivative instruments previously accounted for as cash flow hedges:
| Amount of loss recognized in OCI (effective portion) | Income statement presentation of loss reclassified | |||||||||||||||||
| Year Ended December 31, | from accumulated OCI into income | Year Ended December 31, | ||||||||||||||||
Derivative | 2010 | 2009 | (effective portion) | 2010 | 2009 | |||||||||||||
Interest rate swaps | $ | — | $ | — | Interest expense and related charges | $ | (87 | ) | $ | (184 | ) | |||||||
| Depreciation and amortization | (2 | ) | — | |||||||||||||||
Commodity contracts | — | (30 | ) | Fuel, purchased power costs and delivery fees | — | (16 | ) | |||||||||||
| Operating revenues | (1 | ) | (2 | ) | ||||||||||||||
Total | $ | — | $ | (30 | ) | $ | (90 | ) | $ | (202 | ) | |||||||
There were no transactions designated as cash flow hedges during the year ended December 31, 2010. There were no ineffectiveness net gains or losses related to transactions designated as cash flow hedges in the year ended December 31, 2009.
Accumulated other comprehensive income related to cash flow hedges as of December 31, 2010 and 2009 totaled $69 million and $128 million in net losses (after-tax), respectively, substantially all of which relates to interest rate swaps. We expect that $19 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of December 31, 2010 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.
Derivative Volumes
The following table presents the gross notional amounts of derivative volumes as of December 31, 2010 and 2009:
| December 31, | ||||||||||||
| 2010 | 2009 | |||||||||||
Derivative type | Notional Volume | Unit of Measure | ||||||||||
Interest rate swaps: | ||||||||||||
Floating/fixed | $ | 17,500 | $ | 18,000 | Million US dollars | |||||||
Basis | $ | 15,200 | $ | 16,250 | Million US dollars | |||||||
Natural gas: | ||||||||||||
Long-term hedge forward sales and purchases (a) | 2,681 | 3,402 | Million MMBtu | |||||||||
Locational basis swaps | 1,092 | 1,010 | Million MMBtu | |||||||||
All other | 887 | 1,433 | Million MMBtu | |||||||||
Electricity | 143,776 | 198,230 | GWh | |||||||||
Congestion Revenue Rights (b) | 15,782 | — | GWh | |||||||||
Coal | 6 | 6 | Million tons | |||||||||
Fuel oil | 109 | 161 | Million gallons | |||||||||
| (a) | Represents gross notional forward sales, purchases and options of fixed and basis (price point) transactions in the long-term hedging program. The net amount of these transactions, excluding basis transactions, was 1.0 billion MMBtu and 1.6 billion MMBtu as of December 31, 2010 and 2009, respectively. |
| (b) | Represents gross forward sales and purchases associated with instruments used to hedge price differences between settlement points in the new nodal wholesale market design implemented by ERCOT. |
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Credit Risk-Related Contingent Features of Derivatives
The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of those agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agency; however, due to our credit ratings being below investment grade, substantially all of such collateral posting requirements are already effective.
As of December 31, 2010 and 2009, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $408 million and $687 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $65 million and $152 million as of December 31, 2010 and 2009, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of December 31, 2010 and 2009, the remaining related liquidity requirement would have totaled $18 million and $20 million, respectively, after reduction for net accounts receivable and derivative assets under netting arrangements.
In addition, certain derivative agreements that are collateralized primarily with asset liens include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. As of December 31, 2010 and 2009, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $1.865 billion and $1.482 billion, respectively, (before consideration of the amount of assets under the liens). No cash collateral or letters of credit were posted with these counterparties as of December 31, 2010 to reduce the liquidity exposure, but $489 million of such collateral was posted as of December 31, 2009, with the decline reflecting the return of collateral from counterparties to certain interest rate swaps related to TCEH debt as discussed above in this note. If all the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, had been triggered as of December 31, 2010 and 2009, the remaining related liquidity requirement would have totaled $674 million and $480 million, respectively, after reduction for derivative assets under netting arrangements (before consideration of the amount of assets under the liens). See Note 11 for a description of other obligations that are supported by asset liens.
As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $2.273 billion and $2.169 billion as of December 31, 2010 and 2009, respectively. This amount is before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets under related liens.
Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.
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Concentrations of Credit Risk Related to Derivatives
TCEH has significant concentrations of credit risk with the counterparties to its derivative contracts. As of December 31, 2010, total credit risk exposure to all counterparties related to derivative contracts totaled $4.9 billion (including associated accounts receivable). The net exposure to those counterparties totaled $1.8 billion as of December 31, 2010 after taking into effect master netting arrangements, setoff provisions and collateral. The net exposure, assuming setoff provisions in the event of default across all EFH Corp. consolidated subsidiaries, totaled $1.6 billion. As of December 31, 2010, the credit risk exposure to the banking and financial sector represented 95% of the total credit risk exposure, a significant amount of which is related to the long-term hedging program, and the largest net exposure to a single counterparty totaled approximately $800 million. Exposure to the banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because substantially all of this exposure is with counterparties with credit ratings of “A” or better. However, this concentration increases the risk that a default by any of these counterparties would have a material adverse effect on our financial condition, results of operations and liquidity.
The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies specify authorized risk mitigation tools including, but not limited to, use of standardized master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material adverse changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.
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| 18. | OTHER INVESTMENTS |
The other investments balance consists of the following:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
Nuclear decommissioning trust | $ | 536 | $ | 475 | ||||
Assets related to employee benefit plans, including employee savings programs, net of distributions (a) | 117 | 184 | ||||||
Land | 41 | 43 | ||||||
Miscellaneous other | 3 | 4 | ||||||
Total investments | $ | 697 | $ | 706 | ||||
| (a) | See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010. |
Nuclear Decommissioning Trust
Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor’s customers as a delivery fee surcharge over the life of the plant and deposited in the trust fund. Net gains and losses on investments in the trust fund are offset by a corresponding change in receivables from/payables due to unconsolidated subsidiary, reflecting changes in Oncor’s regulatory asset/liability. A summary of investments in the fund follows:
| December 31, 2010 | ||||||||||||||||
| Cost (a) | Unrealized gain | Unrealized loss | Fair market value | |||||||||||||
Debt securities (b) | $ | 221 | $ | 6 | $ | (4 | ) | $ | 223 | |||||||
Equity securities (c) | 213 | 115 | (15 | ) | 313 | |||||||||||
Total | $ | 434 | $ | 121 | $ | (19 | ) | $ | 536 | |||||||
| December 31, 2009 | ||||||||||||||||
| Cost (a) | Unrealized gain | Unrealized loss | Fair market value | |||||||||||||
Debt securities (b) | $ | 211 | $ | 8 | $ | (3 | ) | $ | 216 | |||||||
Equity securities (c) | 195 | 83 | (19 | ) | 259 | |||||||||||
Total | $ | 406 | $ | 91 | $ | (22 | ) | $ | 475 | |||||||
| (a) | Includes realized gains and losses of securities sold. |
| (b) | The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.61% and 4.44% and an average maturity of 8.8 years and 7.8 years as of December 31, 2010 and 2009, respectively. |
| (c) | The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index. |
Debt securities held as of December 31, 2010 mature as follows: $76 million in one to five years, $52 million in five to ten years and $95 million after ten years.
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The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Realized gains | $ | 1 | $ | 1 | $ | 1 | ||||||
Realized losses | (2 | ) | (6 | ) | (4 | ) | ||||||
Proceeds from sale of securities | 974 | 3,064 | 1,623 | |||||||||
Assets Related to Employee Benefit Plans
The majority of these assets represent cash surrender values of life insurance policies that are purchased to fund liabilities under deferred compensation plans. We pay the premiums and are the beneficiary of these life insurance policies. As of December 31, 2010 and 2009, the face amount of these policies totaled $175 million and $322 million, and the net cash surrender values totaled $68 million and $124 million, respectively. Changes in cash surrender value are netted against premiums paid. Other investment assets held to satisfy deferred compensation liabilities are recorded at fair value.
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| 19. | TERMINATION OF OUTSOURCING ARRANGEMENTS |
In connection with the closing of the Merger, EFH Corp., TCEH and Oncor commenced a review, under the change of control provision, of certain outsourcing arrangements with Capgemini, Capgemini America, Inc. and Capgemini North America, Inc. (collectively, CgE). In 2008, EFH Corp. and TCEH executed a Separation Agreement with CgE. Simultaneous with the execution of that Separation Agreement, Oncor entered into a substantially similar Separation Agreement with CgE. The Separation Agreements principally provide for (i) notice of termination of each of the Master Framework Agreements, dated as of May 17, 2004, as each has been amended, between Capgemini and each of TCEH and Oncor and the related service agreements under each of the Master Framework Agreements and (ii) termination of the joint venture arrangements between EFH Corp. (and its applicable subsidiaries) and CgE. Under the Master Framework Agreements and related services agreements, Capgemini provided outsourced support services, including information technology, customer care and billing, human resources, procurement and certain finance and accounting activities. As a result, during 2008:
| • | the 2.9% limited partnership interest in Capgemini owned by a subsidiary of EFH Corp. was redeemed in exchange for the termination of the license that was granted by a subsidiary of EFH Corp. to Capgemini at the time the Master Framework Agreements were executed in order for Capgemini to use certain information technology assets primarily consisting of capitalized software to provide services to us and third parties; |
| • | we received approximately $70 million in exchange for the termination of a purchase option agreement pursuant to which our subsidiaries had the right to “put” to Capgemini (and Capgemini had the right to “call” from a subsidiary of ours) our 2.9% limited partnership interest in Capgemini and the licensed assets upon the expiration of the Master Framework Agreements in 2014 or, in some circumstances, earlier, and |
| • | Capgemini repaid $25 million (plus accrued interest) representing all amounts owed by Capgemini under the working capital loan provided by us in July 2004. |
Under the Separation Agreements, the parties also entered into a mutual release of all claims under the Master Framework Agreements and related services agreements and the joint venture agreements, subject to certain defined exceptions, resulting in our receipt of $10 million in cash settlement.
The carrying value of the partnership interest was $2.9 million, and the carrying value of the purchase option was $177 million prior to the application of purchase accounting (recorded as a noncurrent asset). The effects of the termination of the outsourcing arrangements, including an accrued liability of $54 million for incremental costs to exit and transition the services, were included in the final purchase price allocation.
The following table summarizes the changes to the exit liability:
| Competitive Electric segment | Regulated Delivery segment | Total | ||||||||||
Liability for exit activities as of January 1, 2009 | $ | 38 | $ | 16 | $ | 54 | ||||||
Payments recorded against liability | (24 | ) | (4 | ) | (28 | ) | ||||||
Other adjustments to the liability (a) | (11 | ) | (10 | ) | (21 | ) | ||||||
Liability for exit activities as of December 31, 2009 | $ | 3 | $ | 2 | $ | 5 | ||||||
Payments recorded against liability | (1 | ) | (2 | ) | (3 | ) | ||||||
Other adjustments to the liability (a) | (2 | ) | — | (2 | ) | |||||||
Liability for exit activities as of December 31, 2010 | $ | — | $ | — | $ | — | ||||||
| (a) | Represents reversal of exit liabilities due primarily to a shorter than expected outsourcing services transition period. |
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| 20. | PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS |
EFH Corp. is the plan sponsor of the EFH Retirement Plan (Retirement Plan), which provides benefits to eligible employees of subsidiaries (participating employers). The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. The interest component of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasury bonds. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs.
Effective October 1, 2007, all new employees, with the exception of employees hired by Oncor, are not eligible to participate in the Retirement Plan. New hires at Oncor are eligible to participate in the Cash Balance Formula of the Retirement Plan. It is our policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations.
We also have supplemental unfunded retirement plans for certain employees whose retirement benefits cannot fully be earned under the qualified Retirement Plan, the information for which is included below.
We offer OPEB in the form of health care and life insurance to eligible employees and their eligible dependents upon the retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service.
Regulatory Recovery of Pension and OPEB Costs
PURA provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, which in addition to Oncor’s own employees consists largely of active and retired personnel engaged in TCEH’s activities, related to service of those additional personnel prior to the deregulation and disaggregation of our businesses effective January 1, 2002. Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Amounts deferred are ultimately subject to regulatory approval. As of December 31, 2010 and 2009, Oncor had recorded regulatory assets totaling $1.048 billion and $889 million, respectively, related to pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilities that otherwise would be recorded as other comprehensive income.
Pension and OPEB Costs Recognized as Expense
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Pension costs | $ | 100 | $ | 44 | $ | 21 | ||||||
OPEB costs | 80 | 70 | 58 | |||||||||
Total benefit costs | $ | 180 | $ | 114 | $ | 79 | ||||||
Less amounts expensed by Oncor (and not consolidated) | (37 | ) | — | — | ||||||||
Less amounts deferred principally as a regulatory asset or property by Oncor | (93 | ) | (66 | ) | (42 | ) | ||||||
Net amounts recognized as expense by EFH Corp. and consolidated subsidiaries | $ | 50 | $ | 48 | $ | 37 | ||||||
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We use the calculated value method to determine the market-related value of the assets held in trust. We include the realized and unrealized gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.
Detailed Information Regarding Pension Benefits
The following information is based on December 31, 2010, 2009 and 2008 measurement dates:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Assumptions Used to Determine Net Periodic Pension Cost: | ||||||||||||
Discount rate | 5.90 | % | 6.90 | % | 6.55 | % | ||||||
Expected return on plan assets | 8.00 | % | 8.25 | % | 8.25 | % | ||||||
Rate of compensation increase | 3.71 | % | 3.75 | % | 3.70 | % | ||||||
Components of Net Pension Cost: | ||||||||||||
Service cost | $ | 42 | $ | 38 | $ | 36 | ||||||
Interest cost | 160 | 159 | 148 | |||||||||
Expected return on assets | (160 | ) | (166 | ) | (165 | ) | ||||||
Amortization of prior service cost | 1 | 1 | 1 | |||||||||
Amortization of net loss | 57 | 12 | 1 | |||||||||
Recognized curtailment loss | — | — | — | |||||||||
Net periodic pension cost | $ | 100 | $ | 44 | $ | 21 | ||||||
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income: | ||||||||||||
Net loss | $ | 27 | $ | 45 | $ | 204 | ||||||
Amortization of net gain | (19 | ) | — | — | ||||||||
Reclassification to regulatory asset | — | — | (6 | ) | ||||||||
Purchase accounting adjustment | — | — | (10 | ) | ||||||||
Total loss (income) recognized in other comprehensive income | $ | 8 | $ | 45 | $ | 188 | ||||||
Total recognized in net periodic benefit cost and other comprehensive income | $ | 108 | $ | 89 | $ | 209 | ||||||
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Assumptions Used to Determine Benefit Obligations: | ||||||||||||
Discount rate | 5.50 | % | 5.90 | % | 6.90 | % | ||||||
Rate of compensation increase | 3.74 | % | 3.71 | % | 3.75 | % | ||||||
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| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
Change in Pension Obligation: | ||||||||
Projected benefit obligation as of beginning of year | $ | 2,742 | $ | 2,337 | ||||
Service cost | 42 | 38 | ||||||
Interest cost | 160 | 160 | ||||||
Actuarial loss | 253 | 326 | ||||||
Benefits paid | (125 | ) | (133 | ) | ||||
Settlements | — | 14 | ||||||
Projected benefit obligation as of end of year | $ | 3,072 | $ | 2,742 | ||||
Accumulated benefit obligation as of end of year | $ | 2,863 | $ | 2,581 | ||||
Change in Plan Assets: | ||||||||
Fair value of assets as of beginning of year | $ | 2,004 | $ | 1,736 | ||||
Actual return on assets | 261 | 292 | ||||||
Employer contributions (a) | 45 | 109 | ||||||
Benefits paid | (125 | ) | (133 | ) | ||||
Fair value of assets as of end of year | $ | 2,185 | $ | 2,004 | ||||
Funded Status: | ||||||||
Projected pension benefit obligation | $ | (3,072 | ) | $ | (2,742 | ) | ||
Fair value of assets | 2,185 | 2,004 | ||||||
Funded status as of end of year | $ | (887 | ) | $ | (738 | ) | ||
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
Amounts Recognized in the Balance Sheet Consist of: | ||||||||
Other noncurrent assets (b) | $ | 10 | $ | 10 | ||||
Other current liabilities | (5 | ) | (4 | ) | ||||
Other noncurrent liabilities | (892 | ) | (744 | ) | ||||
Net liability recognized | $ | (887 | ) | $ | (738 | ) | ||
Amounts Recognized in Accumulated Other Comprehensive Income Income Consist of: | ||||||||
Net loss | $ | 261 | $ | 252 | ||||
Amounts Recognized by Oncor as Regulatory Assets Consist of (c): | ||||||||
Net loss | $ | 616 | $ | 529 | ||||
Prior service cost | — | 1 | ||||||
Net amount recognized | $ | 616 | $ | 530 | ||||
| (a) | 2009 amount included transfers of investments related to the salary deferral and supplemental retirement plans totaling $31 million. |
| (b) | Amounts represent overfunded plans. |
| (c) | Amounts are reflected by EFH Corp. in receivables from unconsolidated subsidiary. |
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The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated benefit obligation (ABO) in excess of the fair value of plan assets.
| December 31, | ||||||||
| 2010 | 2009 | |||||||
Pension Plans with PBO and ABO in Excess Of Plan Assets: | ||||||||
Projected benefit obligations | $ | 3,067 | $ | 2,738 | ||||
Accumulated benefit obligation | 2,858 | 2,577 | ||||||
Plan assets | 2,170 | 1,989 | ||||||
Pension Plan Investment Strategy and Asset Allocations
Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Equity securities are held to achieve returns in excess of passive indexes by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging international markets. Fixed income securities include primarily corporate bonds from a diversified range of companies, US Treasuries and agency securities and money market instruments. Our investment strategy for fixed income investments is to maintain a high grade portfolio of securities which assist us in managing the volatility and magnitude of plan contributions and expense while maintaining sufficient cash and short-term investments to pay near-term benefits and expenses.
The target asset allocation ranges of pension plan investments by asset category are as follows:
Asset Category | Target Allocation Ranges | |
US equities | 15% - 50% | |
International equities | 5% - 20% | |
Fixed income | 40% - 70% | |
Other | 0% - 10% |
Fair Value Measurement of Pension Plan Assets
As of December 31, 2010, pension plan assets measured at fair value (see Note 15) on a recurring basis consisted of the following:
Asset Category | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Interest-bearing cash | $ | — | $ | 69 | $ | — | $ | 69 | ||||||||
Equity securities: | ||||||||||||||||
US | 422 | 94 | — | 516 | ||||||||||||
International | 248 | 84 | — | 332 | ||||||||||||
Fixed income securities: | ||||||||||||||||
Corporate bonds (a) | — | 1,137 | — | 1,137 | ||||||||||||
US Treasuries | — | 21 | — | 21 | ||||||||||||
Other (b) | — | 96 | — | 96 | ||||||||||||
Preferred securities | — | — | 14 | 14 | ||||||||||||
Total assets | $ | 670 | $ | 1,501 | $ | 14 | $ | 2,185 | ||||||||
| (a) | Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s. |
| (b) | Other consists primarily of US agency securities. |
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As of December 31, 2009, pension plan assets measured at fair value on a recurring basis consisted of the following:
Asset Category | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Interest-bearing cash | $ | — | $ | 99 | $ | — | $ | 99 | ||||||||
Equity securities: | ||||||||||||||||
US | 340 | 242 | — | 582 | ||||||||||||
International | 257 | 79 | — | 336 | ||||||||||||
Fixed income securities: | ||||||||||||||||
Corporate bonds (a) | — | 908 | — | 908 | ||||||||||||
US Treasuries | — | 21 | — | 21 | ||||||||||||
Other (b) | — | 44 | — | 44 | ||||||||||||
Preferred securities | — | — | 14 | 14 | ||||||||||||
Total assets | $ | 597 | $ | 1,393 | $ | 14 | $ | 2,004 | ||||||||
| (a) | Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s. |
| (b) | Other consists primarily of US agency securities. |
There was no significant change in the fair values of Level 3 assets in the periods presented.
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Detailed Information Regarding Postretirement Benefits Other Than Pensions
The following OPEB information is based on December 31, 2010, 2009 and 2008 measurement dates:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Assumptions Used to Determine Net Periodic Benefit Cost: | ||||||||||||
Discount rate | 5.90 | % | 6.85 | % | 6.55 | % | ||||||
Expected return on plan assets | 7.60 | % | 7.64 | % | 7.90 | % | ||||||
Components of Net Postretirement Benefit Cost: | ||||||||||||
Service cost | $ | 13 | $ | 10 | $ | 10 | ||||||
Interest cost | 61 | 61 | 59 | |||||||||
Expected return on assets | (15 | ) | (13 | ) | (20 | ) | ||||||
Amortization of net transition obligation | 1 | 1 | 1 | |||||||||
Amortization of prior service cost/(credit) | (1 | ) | (1 | ) | (1 | ) | ||||||
Amortization of net loss | 21 | 12 | 9 | |||||||||
Net periodic OPEB cost | $ | 80 | $ | 70 | $ | 58 | ||||||
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income: | ||||||||||||
Net loss | $ | 14 | $ | 15 | $ | 1 | ||||||
Amortization of net gain | (1 | ) | — | — | ||||||||
Reclassification to regulatory asset | — | — | (28 | ) | ||||||||
Purchase accounting adjustment | — | — | (1 | ) | ||||||||
Total loss (income) recognized in other comprehensive income | $ | 13 | $ | 15 | $ | (28 | ) | |||||
Total recognized in net periodic benefit cost and other comprehensive income | $ | 93 | $ | 85 | $ | 30 | ||||||
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Assumptions Used to Determine Benefit Obligations at Period End: | ||||||||||||
Discount rate | 5.55 | % | 5.90 | % | 6.85 | % | ||||||
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| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
Change in Postretirement Benefit Obligation: | ||||||||
Benefit obligation as of beginning of year | $ | 1,063 | $ | 919 | ||||
Service cost | 13 | 10 | ||||||
Interest cost | 61 | 61 | ||||||
Participant contributions | 17 | 23 | ||||||
Medicare Part D reimbursement | 4 | 6 | ||||||
Actuarial loss | 98 | 108 | ||||||
Benefits paid | (65 | ) | (64 | ) | ||||
Benefit obligation as of end of year | $ | 1,191 | $ | 1,063 | ||||
Change in Plan Assets: | ||||||||
Fair value of assets as of beginning of year | $ | 211 | $ | 198 | ||||
Actual return on assets | 24 | 32 | ||||||
Employer contributions | 24 | 22 | ||||||
Participant contributions | 17 | 23 | ||||||
Benefits paid | (65 | ) | (64 | ) | ||||
Fair value of assets as of end of year | $ | 211 | $ | 211 | ||||
Funded Status: | ||||||||
Benefit obligation | $ | (1,191 | ) | $ | (1,063 | ) | ||
Fair value of assets | 211 | 211 | ||||||
Funded status as of end of year | $ | (980 | ) | $ | (852 | ) | ||
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
Amounts Recognized on the Balance Sheet Consist of: | ||||||||
Other noncurrent liabilities | $ | (980 | ) | $ | (852 | ) | ||
Amounts Recognized in Accumulated Other Comprehensive Income Consist of: | ||||||||
Net loss | $ | 36 | $ | 23 | ||||
Amounts Recognized by Oncor as Regulatory Assets Consist of (a): | ||||||||
Net loss | $ | 296 | $ | 242 | ||||
Prior service cost credit | (5 | ) | (7 | ) | ||||
Net transition obligation | 3 | 4 | ||||||
Net amount recognized | $ | 294 | $ | 239 | ||||
| (a) | Amounts are reflected by EFH Corp. in receivables from unconsolidated subsidiary. |
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The following tables provide information regarding the assumed health care cost trend rates.
| December 31, | ||||||||
| 2010 | 2009 | |||||||
Assumed Health Care Cost Trend Rates-Not Medicare Eligible : | ||||||||
Health care cost trend rate assumed for next year | 9.00 | % | 8.00 | % | ||||
Rate to which the cost trend is expected to decline (the ultimate trend rate) | 5.00 | % | 5.00 | % | ||||
Year that the rate reaches the ultimate trend rate | 2021 | 2016 | ||||||
Assumed Health Care Cost Trend Rates-Medicare Eligible : | ||||||||
Health care cost trend rate assumed for next year | 8.00 | % | 7.00 | % | ||||
Rate to which the cost trend is expected to decline (the ultimate trend rate) | 5.00 | % | 5.00 | % | ||||
Year that the rate reaches the ultimate trend rate | 2021 | 2016 | ||||||
| 1-Percentage Point Increase | 1-Percentage Point Decrease | |||||||
Sensitivity Analysis of Assumed Health Care Cost Trend Rates : | ||||||||
Effect on accumulated postretirement obligation | $ | 156 | $ | (131 | ) | |||
Effect on postretirement benefits cost | 12 | (10 | ) | |||||
OPEB Plan Investment Strategy and Asset Allocations
Our investment objective for the OPEB plan primarily follows the objectives of the Retirement Plan discussed above, while maintaining sufficient cash and short-term investments to pay near-term benefits and expenses. The actual amounts as of December 31, 2010 provided below are consistent with the Company’s asset allocation targets.
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Fair Value Measurement of OPEB Plan Assets
As of December 31, 2010, OPEB plan assets measured at fair value on a recurring basis consisted of the following:
Asset Category | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Interest-bearing cash | $ | — | $ | 11 | $ | — | $ | 11 | ||||||||
Equity securities: | ||||||||||||||||
US | 62 | 4 | — | 66 | ||||||||||||
International | 27 | 4 | — | 31 | ||||||||||||
Fixed income securities: | ||||||||||||||||
Corporate bonds (a) | — | 55 | — | 55 | ||||||||||||
US Treasuries | — | 1 | — | 1 | ||||||||||||
Other (b) | 42 | 4 | — | 46 | ||||||||||||
Preferred securities | — | — | 1 | 1 | ||||||||||||
Total assets | $ | 131 | $ | 79 | $ | 1 | $ | 211 | ||||||||
| (a) | Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s. |
| (b) | Other consists primarily of US agency securities. |
As of December 31, 2009, OPEB plan assets measured at fair value on a recurring basis consisted of the following:
Asset Category | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Interest-bearing cash | $ | — | $ | 18 | $ | — | $ | 18 | ||||||||
Equity securities: | ||||||||||||||||
US | 56 | 13 | — | 69 | ||||||||||||
International | 27 | 4 | — | 31 | ||||||||||||
Fixed income securities: | ||||||||||||||||
Corporate bonds (a) | — | 50 | — | 50 | ||||||||||||
US Treasuries | — | 1 | — | 1 | ||||||||||||
Other (b) | 39 | 2 | — | 41 | ||||||||||||
Preferred securities | — | — | 1 | 1 | ||||||||||||
Total assets | $ | 122 | $ | 88 | $ | 1 | $ | 211 | ||||||||
| (a) | Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s. |
| (b) | Other consists primarily of US agency securities. |
There was no significant change in the fair values of Level 3 assets in the periods presented.
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Expected Long-Term Rate of Return on Assets Assumption
The Retirement Plan strategic asset allocation is determined in conjunction with the plan’s advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.
Retirement Plan | ||||
Asset Class | Expected Long-Term Rate of Return | |||
US equity securities | 8.4 | % | ||
International equity securities | 8.8 | % | ||
Fixed income securities | 5.9 | % | ||
Preferred securities | 0.0 | % | ||
| 7.7 | % | |||
OPEB Plan | ||||
Plan Type | Expected Long-Term Returns | |||
401(h) accounts | 7.7 | % | ||
Life Insurance VEBA | 6.7 | % | ||
Union VEBA | 6.7 | % | ||
Non-Union VEBA | 2.9 | % | ||
| 7.1 | % | |||
Significant Concentrations of Risk
The plans’ investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.
Assumed Discount Rate
We selected the assumed discount rate using the Hewitt Top Quartile yield curve, which is based on actual corporate bond yields and as of December 31, 2010 consisted of 141 corporate bonds rated AA or higher as reported by either Moody’s or S&P.
Amortization in 2011
In 2011, we estimate amortization of the net actuarial loss and prior service cost for the defined benefit pension plan from accumulated other comprehensive income into net periodic benefit cost will be $92 million and $1 million, respectively. We estimate amortization of the net actuarial loss, prior service credit, and transition obligation for the OPEB plan from accumulated other comprehensive income into net periodic benefit cost will be $29 million, a $1 million credit and $1 million, respectively.
Contributions in 2011 and 2010
Estimated funding for calendar year 2011 totals $175 million for the Retirement Plan and $26 million for the OPEB plan. We made pension and OPEB contributions of $45 million and $25 million, respectively, in 2010, of which $58 million was contributed by Oncor.
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Future Benefit Payments
Estimated future benefit payments to beneficiaries are as follows:
| 2011 | 2012 | 2013 | 2014 | 2015 | 2016-20 | |||||||||||||||||||
Pension benefits | $ | 144 | $ | 153 | $ | 164 | $ | 169 | $ | 179 | $ | 1,070 | ||||||||||||
OPEB | $ | 62 | $ | 65 | $ | 62 | $ | 66 | $ | 70 | $ | 404 | ||||||||||||
Medicare Part D subsidies | $ | (7 | ) | $ | (7 | ) | $ | (8 | ) | $ | (8 | ) | $ | (9 | ) | $ | (52 | ) | ||||||
Thrift Plan
Our employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% of the first 6% of employee contributions for employees who are covered under the Cash Balance Formula of the Retirement Plan, and 75% of the first 6% of employee contributions for employees who are covered under the Traditional Retirement Plan Formula of the Retirement Plan. Employer matching contributions are made in cash and may be allocated by participants to any of the plan’s investment options. Our contributions to the Thrift Plan totaled $19 million, $28 million and $25 million in the years ended December 31, 2010, 2009 and 2008, respectively.
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| 21. | STOCK-BASED COMPENSATION |
EFH Corp. 2007 Stock Incentive Plan
In December 2007, we established the 2007 Stock Incentive Plan for Key Employees of EFH Corp. and its Affiliates (2007 SIP). Incentive awards under the 2007 SIP may be granted to directors and officers and qualified managerial employees of EFH Corp. or its subsidiaries or affiliates in the form of non-qualified stock options, stock appreciation rights, restricted shares, deferred shares, shares of common stock, the opportunity to purchase shares of common stock and other awards that are valued in whole or in part by reference to, or are otherwise based on the fair market value of EFH Corp.’s shares of common stock. The 2007 SIP permits the grant of awards for 72 million shares of common stock, subject to adjustments under applicable laws for certain events, such as a change in control, and no such grants may be issued after December 26, 2017. Shares related to grants that are forfeited, terminated, cancelled, expire unexercised, withheld to satisfy tax withholding obligations, or are repurchased by the Company are available for new grants under the 2007 SIP.
Stock Options— Under the terms of the 2007 SIP, options to purchase 3.8 million, 14.7 million and 33.1 million shares of EFH Corp. common stock were granted to certain management employees in 2010, 2009 and 2008, respectively. Of the options granted in 2010 and 2009, 1.6 million and 9.2 million, respectively, were granted in exchange for previously granted options. Vested awards must be exercised within 10 years of the grant date. The options initially provided the holder the right to purchase EFH Corp. common stock for $5.00 per share. The terms of the options were fixed at grant date. The stock option awards under the 2007 SIP consist of three types of stock options. One-half of the options initially granted vest solely based upon continued employment over a specific period of time, generally five years, with the options vesting ratably on an annual basis over the period (Time-Based Options). One-half of the options initially granted vest based upon both continued employment and the achievement of targeted five-year EFH Corp. EBITDA levels (Performance-Based Options). The Performance-Based Options may also vest in part or in full upon the occurrence of certain specified liquidity events. All options remain exercisable for ten years from the date of grant. Prior to vesting, expenses are recorded if the achievement of the EBITDA levels is probable, and amounts recorded are adjusted or reversed if the probability of achievement of such levels changes. Probability of vesting is evaluated at least each quarter.
In October 2009, in consideration of the recent economic dislocation and the desire to provide incentives for retention, grantees of Performance-Based Options (excluding named executive officers and a small group of other employees) were provided an offer, which substantially all accepted, to exchange their unvested Performance-Based Options granted under the 2007 SIP with a strike price of $5.00 per share and a vesting schedule through October 2012 for new time-based stock options (Cliff-Vesting Options) granted under the 2007 SIP with a strike price of $3.50 per share (the then most recent market valuation of each share), with one-half of these options vesting in September 2012 and one-half of these options vesting in September 2014. Additionally, 3.1 million Cliff-Vesting Options were granted to certain named executive officers and a small group of other employees under the 2007 SIP with a strike price of $3.50 per share, vesting in September 2014. Substantially all of this group of employees also accepted an offer to exchange half of their unvested Performance-Based Options under the 2007 SIP with a strike price of $5.00 per share and a vesting schedule through December 2012 for new time-based stock options granted under the 2007 SIP with a strike price of $3.50 per share, vesting in September 2014.
In December 2010, in consideration of the desire to enhance retention incentives, EFH Corp. offered employee grantees of all stock options (excluding named executive officers and a limited number of other employees) the right to exchange their vested and unvested options for restricted stock units (at a ratio of two options for each stock unit). The restricted stock units vest as common shares of EFH Corp. in September 2014. The exchange offer is expected to close in late February 2011.
The fair value of all options granted was estimated using the Black-Scholes option pricing model and the assumptions noted in the table below. Since EFH Corp. is a private company, expected volatility is based on actual historical experience of comparable publicly-traded companies for a term corresponding to the expected life of the options. The expected life represents the period of time that options granted are expected to be outstanding and is calculated using the simplified method prescribed by the SEC Staff Accounting Bulletin No. 107. The simplified method was used since EFH Corp. does not have stock option history upon which to base the estimate of the expected life and data for similar companies was not reasonably available. The risk-free rate is based on the US Treasury security with terms equal to the expected life of the option as of the grant date.
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The weighted average grant-date fair value of the Time-Based Options granted in 2010, 2009 and 2008 was $1.16, $1.32 and $1.89 per option, respectively. The weighted-average grant-date fair value of the Performance-Based Options granted in 2009 and 2008 ranged from $1.16 to $1.91 and $1.73 to $2.25, respectively, depending upon the performance period. There were no Performance-Based Options granted in 2010.
Assumptions supporting the fair values were as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||
Assumptions | Time-Based Options | Performance-Based Options | ||||||||||
Expected volatility | 30% – 35% | 30% | 30% – 33% | N/A | 30% | 30% – 33% | ||||||
Expected annual dividend | — | — | — | — | — | — | ||||||
Expected life (in years) | 6.1 – 7.3 | 6.4 – 7.4 | 6.0 – 6.5 | N/A | 5.3 – 7.6 | 5.0 – 7.3 | ||||||
Risk-free rate | 2.69% – 3.20% | 2.54% – 3.14% | 1.51% – 3.50% | N/A | 2.51% – 3.25% | 1.35% – 3.64% | ||||||
Compensation expense for Time-Based Options is based on the grant-date fair value and recognized over the vesting period as employees perform services. During 2010, 2009 and 2008, $13.5 million, $8.6 million and $11.9 million, respectively, was recognized as expense for Time-Based Options.
As of December 31, 2010, there was approximately $30.6 million of unrecognized compensation expense related to nonvested Time-Based Options, which is expected to be recognized ratably over a remaining weighted-average period of approximately three to five years.
A summary of Time-Based Options activity is presented below:
| Year Ended December 31, 2010 | ||||||||||||
Options | Options (millions) | Weighted Average Exercise Price | Aggregate Intrinsic Value (millions) | |||||||||
Total outstanding as of beginning of period | 35.6 | $ | 4.42 | $ | — | |||||||
Granted | 3.8 | 3.41 | — | |||||||||
Exercised | — | — | — | |||||||||
Forfeited | (2.2 | ) | 4.53 | — | ||||||||
Total outstanding as of end of period (weighted average remaining term of 7 – 10 years) | 37.2 | 4.31 | — | |||||||||
Exercisable as of end of period (weighted average remaining term of 7 – 10 years) | (4.8 | ) | 4.71 | — | ||||||||
Expected forfeitures | (0.1 | ) | 5.00 | — | ||||||||
Expected to vest as of end of period (weighted average remaining term of 7 – 10 years) | 32.3 | 4.25 | — | |||||||||
| Year Ended December 31, 2009 | ||||||||||||
Options | Options (millions) | Weighted Average Exercise Price | Aggregate Intrinsic Value (millions) | |||||||||
Total outstanding as of beginning of period | 24.6 | $ | 5.00 | $ | — | |||||||
Granted | 13.9 | 3.50 | — | |||||||||
Exercised | — | — | — | |||||||||
Forfeited | (2.9 | ) | 5.00 | — | ||||||||
Total outstanding as of end of period (weighted average remaining term of 8 – 10 years) | 35.6 | 4.42 | — | |||||||||
Exercisable as of end of period (weighted average remaining term of 8 – 10 years) | (4.7 | ) | 5.00 | — | ||||||||
Expected forfeitures | (0.3 | ) | 5.00 | — | ||||||||
Expected to vest as of end of period (weighted average remaining term of 8 – 10 years) | 30.6 | 4.32 | — | |||||||||
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| Year Ended December 31, 2008 | ||||||||||||
Options | Options (millions) | Weighted Average Exercise Price | Aggregate Intrinsic Value (millions) | |||||||||
Total outstanding as of beginning of period | 9.8 | $ | 5.00 | $ | — | |||||||
Granted | 16.8 | 5.00 | — | |||||||||
Exercised | — | — | — | |||||||||
Forfeited | (2.0 | ) | 5.00 | — | ||||||||
Total outstanding as of end of period (weighted average remaining term of 9 years) | 24.6 | 5.00 | — | |||||||||
Exercisable as of end of period (weighted average remaining term of 9 years) | (4.7 | ) | 5.00 | — | ||||||||
Expected forfeitures | (0.4 | ) | 5.00 | — | ||||||||
Expected to vest as of end of period (weighted average remaining term of 9 years) | 19.5 | 5.00 | — | |||||||||
| Year Ended December 31, | ||||||||||||||||||||||||
| 2010 | 2009 | 2008 | ||||||||||||||||||||||
Nonvested Options | Options (millions) | Weighted Average Grant- Date Fair Value | Options (millions) | Weighted Average Grant- Date Fair Value | Options (millions) | Weighted Average Grant- Date Fair Value | ||||||||||||||||||
Total nonvested as of beginning of period | 26.2 | $ | 1.67 | 19.9 | $ | 2.05 | 9.8 | $ | 1.92 | |||||||||||||||
Granted | 3.8 | 1.16 | 13.9 | 1.32 | 16.8 | 1.89 | ||||||||||||||||||
Vested | (4.8 | ) | 1.63 | (4.7 | ) | 1.86 | (4.7 | ) | 1.80 | |||||||||||||||
Forfeited | (2.2 | ) | 1.70 | (2.9 | ) | 1.85 | (2.0 | ) | 1.92 | |||||||||||||||
Total nonvested as of end of period | 23.0 | 1.59 | 26.2 | 1.67 | 19.9 | 2.05 | ||||||||||||||||||
Compensation expense for Performance-Based Options is based on the grant-date fair value and recognized over the requisite performance and service periods for each tranche of options depending upon the achievement of financial performance, or if certain liquidity events occur, as discussed above. Additionally, most participants’ Performance-Based Options were exchanged for Time-Based Options in 2009. Expense recognized for Performance-Based Options totaled $3.4 million in 2010 and $8.1 million in 2008.
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As of December 31, 2010, there was approximately $10.5 million of unrecognized compensation expense related to nonvested Performance-Based Options, which we could record as an expense over a remaining weighted-average period of approximately three to five years, subject to the achievement of financial performance being probable. A total of 4.8 million of the 2008 and 2.0 million of the 2009 Performance-Based Options have vested.
A summary of Performance-Based Options activity is presented below:
| Year Ended December 31, 2010 | ||||||||||||
Options | Options (millions) | Weighted Average Exercise Price | Aggregate Intrinsic Value (millions) | |||||||||
Outstanding as of beginning of period | 12.5 | $ | 4.90 | $ | — | |||||||
Granted | — | — | — | |||||||||
Exercised | — | — | — | |||||||||
Forfeited | (1.4 | ) | 5.00 | — | ||||||||
Exchanged | — | — | — | |||||||||
Total outstanding as of end of period (weighted average remaining term of 7 – 10 years) | 11.1 | 4.89 | — | |||||||||
Exercisable as of end of period (weighted average remaining term of 7 – 10 years) | (2.0 | ) | 5.00 | — | ||||||||
Expected forfeitures | — | — | — | |||||||||
Expected to vest as of end of period (weighted average remaining term of 7 – 10 years) | 9.1 | 4.87 | — | |||||||||
| Year Ended December 31, 2009 | ||||||||||||
Options | Options (millions) | Weighted Average Exercise Price | Aggregate Intrinsic Value (millions) | |||||||||
Outstanding as of beginning of period | 23.9 | $ | 5.00 | $ | — | |||||||
Granted | 0.8 | 3.50 | — | |||||||||
Exercised | — | — | — | |||||||||
Forfeited | (3.0 | ) | 5.00 | — | ||||||||
Exchanged | (9.2 | ) | 5.00 | — | ||||||||
Total outstanding as of end of period (weighted average remaining term of 8 – 10 years) | 12.5 | 4.90 | — | |||||||||
Exercisable as of end of period (weighted average remaining term of 8 – 10 years) | (4.8 | ) | 5.00 | — | ||||||||
Expected forfeitures | (0.3 | ) | 5.00 | — | ||||||||
Expected to vest as of end of period (weighted average remaining term of 8 – 10 years) | 7.4 | 4.90 | — | |||||||||
| Year Ended December 31, 2008 | ||||||||||||
Options | Options (millions) | Weighted Average Exercise Price | Aggregate Intrinsic Value (millions) | |||||||||
Outstanding as of beginning of period | 9.8 | $ | 5.00 | $ | — | |||||||
Granted | 16.2 | 5.00 | — | |||||||||
Exercised | — | — | — | |||||||||
Forfeited | (2.1 | ) | 5.00 | — | ||||||||
Total outstanding as of end of period (weighted average remaining term of 9 years) | 23.9 | 5.00 | — | |||||||||
Exercisable as of end of period (weighted average remaining term of 9 years) | — | — | — | |||||||||
Expected forfeitures | (0.5 | ) | 5.00 | — | ||||||||
Expected to vest as of end of period (weighted average remaining term of 9 years) | 23.4 | 5.00 | — | |||||||||
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| Year Ended December 31, | ||||||||||||||||||||||||
| 2010 | 2009 | 2008 | ||||||||||||||||||||||
Nonvested Options | Options (millions) | Grant-Date Fair Value | Options (millions) | Grant-Date Fair Value | Options (millions) | Grant-Date Fair Value | ||||||||||||||||||
Total nonvested as of beginning of period | 7.7 | $ | 1.16 – 2.11 | 23.9 | $ | 1.73 – 2.21 | 9.8 | $ | 1.74 – 2.09 | |||||||||||||||
Granted | — | — | 0.8 | 1.16 – 1.91 | 16.2 | 1.73 – 2.25 | ||||||||||||||||||
Vested | (2.0 | ) | 1.62 – 1.87 | (4.8 | ) | 1.73 – 2.21 | — | — | ||||||||||||||||
Forfeited | (1.4 | ) | 1.60 – 1.87 | (3.0 | ) | 1.73 – 2.21 | (2.1 | ) | 1.74 – 2.09 | |||||||||||||||
Exchanged | — | — | (9.2 | ) | — | — | — | |||||||||||||||||
Total nonvested as of end of period | 4.3 | 1.16 – 2.11 | 7.7 | 1.16 – 2.11 | 23.9 | 1.73 – 2.21 | ||||||||||||||||||
Other Share and Share-Based Awards —In 2008, we granted 2.4 million deferred share awards, each of which represents the right to receive one share of EFH Corp. stock, to certain management employees who agreed to forego share-based awards that vested at the Merger date. The deferred share awards are fully vested and are payable in cash or stock upon the earlier of a change of control or separation of service. No expense was recorded in 2008 related to these awards. An additional 1.2 million deferred share awards were granted to certain management employees in 2008, approximately half of which are payable in cash or stock and the balance payable in stock; 1.0 million of these awards have since vested or have been surrendered upon termination of employment. Expenses recognized in 2010, 2009 and 2008 related to these grants totaled $0.4 million, $3.7 million and $2.2 million, respectively. Deferred share awards that are payable in cash or stock are accounted for as liability awards; therefore, the effects of changes in value of EFH Corp. shares are recognized in earnings. As a result of the decline in value of EFH Corp. shares, share-based compensation expense in 2010 and 2009 was reduced by $3.3 million and $3.6 million, respectively.
We granted 2.7 million shares of EFH Corp. stock in 2010, 1.5 million shares in 2009 and 1.7 million shares in 2008, to board members and other non-employees. The shares vest over periods of one to two years, and a portion may be settled in cash. Expense recognized in 2010, 2009 and 2008 related to these grants totaled $4.7 million, $4.0 million and $8.2 million, respectively.
Stock Appreciation Rights –In 2008, Oncor established the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan (the SARs Plan) under which certain employees of Oncor and its subsidiaries may be granted stock appreciation rights (SARs) payable in cash, or in some circumstances, Oncor units. Two types of SARs may be granted under the SARs Plan. Time-based SARs (Time SARs) vest solely based upon continued employment ratably on an annual basis on each of the first five anniversaries of the grant date. Performance-based SARs (Performance SARs) vest based upon both continued employment and the achievement of a predetermined level of Oncor EBITDA over time, generally ratably over five years based upon annual Oncor EBITDA levels, with provisions for vesting if the annual levels are not achieved but cumulative two- or three-year total Oncor EBITDA levels are achieved. Time and Performance SARs may also vest in part or in full upon the occurrence of certain specified liquidity events and are exercisable only upon the occurrence of certain specified liquidity events. Since the exercisability of the Time and Performance SARs is conditioned upon the occurrence of a liquidity event, compensation expense will not be recorded until it is probable that a liquidity event will occur. Generally, awards under the SARs Plan terminate on the tenth anniversary of the grant, unless the participant’s employment is terminated earlier under certain circumstances.
In February 2009, Oncor implemented a similar plan for primarily non-employee members of Oncor’s board of directors. The terms and conditions are similar to the SARs Plan with the exception that SARs granted to non-employee board members vest in eight equal quarterly installments over a two-year period.
SARs are generally payable in cash based on the fair market value of the SAR on the date of exercise. No SARs were granted under the SARs Plan during the year ended December 31, 2009. Oncor granted 6.9 million Time SARs under the SARs Plan during the year ended December 31, 2008, and Time SARS vested as of December 31, 2009 totaled 2.8 million. Oncor granted 6.9 million Performance SARs under the SARs Plan during the year ended December 31, 2008, and Performance SARs vested as of December 31, 2009 totaled 1.4 million. Oncor granted 55 thousand SARs under the Director SARs Plan during the year ended December 31, 2009, and SARs vested under the Director SARs Plan as of December 31, 2009 totaled 27.5 thousand. There were no SARs under either plan eligible for exercise as of December 31, 2009. See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010.
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| 22. | RELATED–PARTY TRANSACTIONS |
The following represent the significant related-party transactions of EFH Corp.:
| • | We incur an annual management fee under the terms of a management agreement with the Sponsor Group for which we accrued $37 million, $36 million and $35 million for the years ended December 31, 2010, 2009 and 2008, respectively. The fee is reported as SG&A expense. |
| • | In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of GS Capital Partners and Kohlberg Kravis Roberts & Co. L.P. (KKR), a member of the Sponsor Group, have from time to time engaged in commercial banking and financial advisory transactions with us in the normal course of business. |
| • | Fees paid to Goldman, Sachs & Co. (Goldman), an affiliate of GS Capital Partners, related to debt issuances and exchanges totaled $11 million in 2010, described as follows. Goldman acted as an initial purchaser in the issuance of $500 million principal amount of EFH Corp. 10% Notes in January 2010 as discussed in Note 11 and received fees totaling $3 million. Goldman acted as a dealer manager and solicitation agent in the debt exchange offers completed in August 2010 as discussed in Note 11 and received fees of $7 million. Goldman also acted as an initial purchaser in the issuance of $350 million principal amount of TCEH 15% Senior Secured Second Lien Notes (Series B) in October 2010 as discussed in Note 11 and received fees totaling $1 million. |
| • | Affiliates of the Sponsor Group participated in debt exchange offers completed in November 2009 by EFH Corp., EFIH and EFIH Finance to exchange new senior secured notes for certain EFH Corp. and TCEH notes as discussed in Note 11. Goldman and KKR Capital Markets LLC, an affiliate of KKR, acted as dealer managers and TPG Capital, L.P. served as an advisor in the exchange offers. These affiliates were compensated for their services in accordance with the terms of the agreement. These fees totaled $1 million. |
| • | Affiliates of Goldman are parties to certain commodity and interest rate hedging transactions with us in the normal course of business. |
| • | Affiliates of the Sponsor Group may sell or acquire debt or debt securities issued by us in open market transactions or through loan syndications. |
The following transactions reflect the deconsolidation of Oncor Holdings effective January 1, 2010 as discussed in Notes 1 and 3.
| • | TCEH’s retail operations incur electricity delivery fees charged by Oncor, which totaled $1.1 billion for the year ended December 31, 2010. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheet as of December 31, 2010 reflects amounts due currently to Oncor totaling $143 million (included in payables due to unconsolidated subsidiary), primarily related to these electricity delivery fees. |
| • | Oncor’s bankruptcy-remote financing subsidiary has issued securitization bonds to recover generation-related regulatory assets through a transition surcharge to its customers. Oncor’s incremental income taxes related to the transition surcharges it collects are being reimbursed by TCEH. Therefore, the balance sheet reflects a noninterest bearing note payable to Oncor of $217 million ($39 million current portion included in payables due to unconsolidated subsidiary) as of December 31, 2010. TCEH’s payments on the note totaled $37 million for the year ended December 31, 2010. |
| • | TCEH reimburses Oncor for interest expense on Oncor’s bankruptcy-remote financing subsidiary’s securitization bonds. This interest expense, which is paid on a monthly basis, totaled $37 million for the year ended December 31, 2010. |
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| • | A subsidiary of EFH Corp. charges Oncor for financial and other administrative services at cost, which totaled $36 million for the year ended December 31, 2010. |
| • | Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility, reported in other investments on the balance sheet, is funded by a delivery fee surcharge billed to REPs by Oncor and remitted monthly to TCEH (totaling $16 million for the year ended December 31, 2010), with the intent that the trust fund assets will be sufficient to fund the decommissioning liability, reported in noncurrent liabilities on the balance sheet. Income and expenses associated with the trust fund and the decommissioning liability incurred by us are offset by a net change in the intercompany receivable/payable with Oncor, which in turn results in a change in Oncor’s net regulatory asset/liability. As of December 31, 2010, the excess of the trust fund balance over the decommissioning liability resulted in a payable to Oncor totaling $206 million included in noncurrent liabilities due to unconsolidated subsidiary in the balance sheet. |
The intercompany receivable/payable with Oncor has changed from a receivable of $85 million as of January 1, 2010 to a payable of $206 million as of December 31, 2010 due to a new decommissioning cost estimate completed in the second quarter 2010 that resulted in a decline of the liability. The new cost estimate was completed in accordance with regulatory requirements to perform a cost estimate every five years. The lower estimated liability was driven by lower cost escalation assumptions in the new estimate. (Also see Note 24 under “Asset Retirement Obligations.”)
| • | We file a consolidated federal income tax return; however, Oncor Holdings’ federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., are recorded as if Oncor Holdings files its own income tax return. As of December 31, 2010, the amount due to Oncor Holdings totaled $72 million and is included in payables due to unconsolidated subsidiary. Income tax payments from Oncor totaled $107 million in the year ended December 31, 2010. |
| • | Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, as of December 31, 2010, TCEH had posted a letter of credit in the amount of $14 million for the benefit of Oncor. |
| • | EFH Corp. and Oncor are jointly and severally liable for the funding of the EFH Corp. pension plan and a portion of the OPEB plan obligations. EFH Corp. is liable for the majority of the OPEB plan obligations. Oncor has contractually agreed to reimburse EFH Corp. with respect to certain pension plan and OPEB liabilities. Accordingly, as of December 31, 2010, the balance sheet of EFH Corp. reflects such unfunded liabilities and a corresponding receivable from Oncor in the amount of $1.463 billion, classified as noncurrent, which represents the portion of the obligations recoverable by Oncor under regulatory rate-setting provisions and reported by Oncor in its balance sheet. |
| • | Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH would be required to post a letter of credit in an amount equal to $170 million to secure its payment obligations to Oncor in the event, which has not occurred, two or more rating agencies downgrade Oncor’s credit ratings below investment grade. |
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| 23. | SEGMENT INFORMATION |
Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.
The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales to residential and business customers, all largely in Texas. These activities are conducted by TCEH.
The Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly-owned bankruptcy-remote financing subsidiary. See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings and its subsidiaries effective as of January 1, 2010.
Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued businesses, general corporate expenses and interest on EFH Corp. (parent entity), EFIH and EFCH debt.
The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. We evaluate performance based on income from continuing operations. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.
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| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Operating revenues | ||||||||||||
Competitive Electric | $ | 8,235 | $ | 7,911 | $ | 9,787 | ||||||
Regulated Delivery | — | 2,690 | 2,580 | |||||||||
Corp. and Other | — | 20 | 37 | |||||||||
Eliminations | — | (1,075 | ) | (1,040 | ) | |||||||
Consolidated | $ | 8,235 | $ | 9,546 | $ | 11,364 | ||||||
Regulated revenues — included in operating revenues | ||||||||||||
Competitive Electric | $ | — | $ | — | $ | — | ||||||
Regulated Delivery | — | 2,690 | 2,580 | |||||||||
Corp. and Other | — | — | — | |||||||||
Eliminations | — | (1,051 | ) | (1,001 | ) | |||||||
Consolidated | $ | — | $ | 1,639 | $ | 1,579 | ||||||
Affiliated revenues — included in operating revenues | ||||||||||||
Competitive Electric | $ | — | $ | 8 | $ | 7 | ||||||
Regulated Delivery | — | 1,051 | 1,001 | |||||||||
Corp. and Other | — | 16 | 32 | |||||||||
Eliminations | — | (1,075 | ) | (1,040 | ) | |||||||
Consolidated | $ | — | $ | — | $ | — | ||||||
Depreciation and amortization | ||||||||||||
Competitive Electric | $ | 1,380 | $ | 1,172 | $ | 1,092 | ||||||
Regulated Delivery | — | 557 | 492 | |||||||||
Corp. and Other | 27 | 25 | 26 | |||||||||
Eliminations | — | — | — | |||||||||
Consolidated | $ | 1,407 | $ | 1,754 | $ | 1,610 | ||||||
Equity in earnings (losses) of unconsolidated subsidiaries (net of tax) | ||||||||||||
Competitive Electric | $ | — | $ | (7 | ) | $ | (10 | ) | ||||
Regulated Delivery | 277 | (2 | ) | (4 | ) | |||||||
Corp. and Other | — | (3 | ) | (5 | ) | |||||||
Eliminations | — | 12 | 19 | |||||||||
Consolidated | $ | 277 | $ | — | $ | — | ||||||
Interest income | ||||||||||||
Competitive Electric | $ | 91 | $ | 64 | $ | 61 | ||||||
Regulated Delivery | — | 43 | 45 | |||||||||
Corp. and Other | 151 | 147 | 100 | |||||||||
Eliminations | (232 | ) | (209 | ) | (179 | ) | ||||||
Consolidated | $ | 10 | $ | 45 | $ | 27 | ||||||
Interest expense and related charges | ||||||||||||
Competitive Electric | $ | 2,957 | $ | 1,946 | $ | 4,010 | ||||||
Regulated Delivery | — | 346 | 317 | |||||||||
Corp. and Other | 829 | 829 | 787 | |||||||||
Eliminations | (232 | ) | (209 | ) | (179 | ) | ||||||
Consolidated | $ | 3,554 | $ | 2,912 | $ | 4,935 | ||||||
Income tax expense (benefit) | ||||||||||||
Competitive Electric | $ | 359 | $ | 407 | $ | (450 | ) | |||||
Regulated Delivery | — | 173 | 221 | |||||||||
Corp. and Other | 30 | (213 | ) | (242 | ) | |||||||
Eliminations | — | — | — | |||||||||
Consolidated | $ | 389 | $ | 367 | $ | (471 | ) | |||||
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| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Net income (loss) | ||||||||||||
Competitive Electric | $ | (3,463 | ) | $ | 631 | $ | (8,929 | ) | ||||
Regulated Delivery | 277 | 320 | (486 | ) | ||||||||
Corp. and Other | 374 | (543 | ) | (583 | ) | |||||||
Eliminations | — | — | — | |||||||||
Consolidated | $ | (2,812 | ) | $ | 408 | $ | (9,998 | ) | ||||
Investment in equity investees | ||||||||||||
Competitive Electric | $ | — | $ | 42 | $ | (2 | ) | |||||
Regulated Delivery | 5,544 | — | — | |||||||||
Corp. and Other | — | — | — | |||||||||
Eliminations | — | — | — | |||||||||
Consolidated | $ | 5,544 | $ | 42 | $ | (2 | ) | |||||
Total assets | ||||||||||||
Competitive Electric | $ | 39,202 | $ | 43,302 | $ | 43,061 | ||||||
Regulated Delivery | 5,544 | 16,246 | 15,772 | |||||||||
Corp. and Other | 5,045 | 4,355 | 3,526 | |||||||||
Eliminations | (3,403 | ) | (4,241 | ) | (3,096 | ) | ||||||
Consolidated | $ | 46,388 | $ | 59,662 | $ | 59,263 | ||||||
Capital expenditures | ||||||||||||
Competitive Electric | $ | 796 | $ | 1,324 | $ | 1,914 | ||||||
Regulated Delivery | — | 998 | 919 | |||||||||
Corp. and Other | 42 | 26 | 16 | |||||||||
Eliminations | — | — | — | |||||||||
Consolidated | $ | 838 | $ | 2,348 | $ | 2,849 | ||||||
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| 24. | SUPPLEMENTARY FINANCIAL INFORMATION |
Regulated Versus Unregulated Operations
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Operating revenues | ||||||||||||
Regulated | $ | — | $ | 2,690 | $ | 2,580 | ||||||
Unregulated | 8,235 | 7,931 | 9,824 | |||||||||
Intercompany sales eliminations — regulated | — | (1,051 | ) | (1,001 | ) | |||||||
Intercompany sales eliminations — unregulated | — | (24 | ) | (39 | ) | |||||||
Total operating revenues | 8,235 | 9,546 | 11,364 | |||||||||
Fuel, purchased power and delivery fees — unregulated (a) | (4,371 | ) | (2,878 | ) | (4,595 | ) | ||||||
Net gain from commodity hedging and trading activities — unregulated | 2,161 | 1,736 | 2,184 | |||||||||
Operating costs — regulated | — | (908 | ) | (828 | ) | |||||||
Operating costs — unregulated | (837 | ) | (690 | ) | (675 | ) | ||||||
Depreciation and amortization — regulated | — | (557 | ) | (492 | ) | |||||||
Depreciation and amortization — unregulated | (1,407 | ) | (1,197 | ) | (1,118 | ) | ||||||
Selling, general and administrative expenses — regulated | — | (194 | ) | (164 | ) | |||||||
Selling, general and administrative expenses — unregulated | (751 | ) | (874 | ) | (793 | ) | ||||||
Franchise and revenue-based taxes — regulated | — | (250 | ) | (255 | ) | |||||||
Franchise and revenue-based taxes — unregulated | (106 | ) | (109 | ) | (108 | ) | ||||||
Impairment of goodwill | (4,100 | ) | (90 | ) | (8,860 | ) | ||||||
Other income | 2,051 | 204 | 80 | |||||||||
Other deductions | (31 | ) | (97 | ) | (1,301 | ) | ||||||
Interest income | 10 | 45 | 27 | |||||||||
Interest expense and other charges | (3,554 | ) | (2,912 | ) | (4,935 | ) | ||||||
Income (loss) before income taxes and equity in earnings of unconsolidated subsidiaries | $ | (2,700 | ) | $ | 775 | $ | (10,469 | ) | ||||
| (a) | Includes unregulated cost of fuel consumed of $1.430 billion in 2010, $1.269 billion in 2009 and $1.604 billion in 2008. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations. |
Interest Expense and Related Charges
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps) | $ | 2,681 | $ | 2,955 | $ | 3,399 | ||||||
Accrued interest to be paid with additional toggle notes (Note 11) | 446 | 524 | 83 | |||||||||
Unrealized mark-to-market net (gain) loss on interest rate swaps | 207 | (696 | ) | 1,477 | ||||||||
Amortization of interest rate swap losses at dedesignation of hedge accounting | 87 | 184 | 66 | |||||||||
Amortization of fair value debt discounts resulting from purchase accounting | 63 | 82 | 75 | |||||||||
Amortization of debt issuance costs and discounts | 130 | 140 | 146 | |||||||||
Capitalized interest | (60 | ) | (277 | ) | (311 | ) | ||||||
Total interest expense and related charges | $ | 3,554 | $ | 2,912 | $ | 4,935 | ||||||
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Restricted Cash
| December 31, 2010 | December 31, 2009 | |||||||||||||||
| Current Assets | Noncurrent Assets | Current Assets | Noncurrent Assets | |||||||||||||
Amounts related to TCEH’s Letter of Credit Facility (See Note 11) | $ | — | $ | 1,135 | $ | — | $ | 1,135 | ||||||||
Amounts related to margin deposits held | 33 | — | 1 | — | ||||||||||||
Amounts related to securitization (transition) bonds (a) | — | — | 47 | 14 | ||||||||||||
Total restricted cash | $ | 33 | $ | 1,135 | $ | 48 | $ | 1,149 | ||||||||
| (a) | See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010. |
Inventories by Major Category
| December 31, | ||||||||
| 2010 | 2009 | |||||||
Materials and supplies (a) | $ | 162 | $ | 248 | ||||
Fuel stock | 198 | 204 | ||||||
Natural gas in storage | 35 | 33 | ||||||
Total inventories | $ | 395 | $ | 485 | ||||
| (a) | See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010. |
Property, Plant and Equipment
| December 31, | ||||||||
| 2010 | 2009 | |||||||
Competitive Electric: | ||||||||
Generation and mining | $ | 22,686 | $ | 20,755 | ||||
Nuclear fuel (net of accumulated amortization of $610 and $426) | 353 | 430 | ||||||
Other assets | 30 | 27 | ||||||
Regulated Delivery (a): | ||||||||
Transmission | — | 3,917 | ||||||
Distribution | — | 8,778 | ||||||
Other assets | — | 174 | ||||||
Corporate and Other | 186 | 161 | ||||||
Total | 23,255 | 34,242 | ||||||
Less accumulated depreciation | 3,545 | 6,633 | ||||||
Net of accumulated depreciation | 19,710 | 27,609 | ||||||
Construction work in progress: | ||||||||
Competitive Electric | 646 | 2,163 | ||||||
Regulated Delivery (a) | — | 321 | ||||||
Corporate and Other | 10 | 15 | ||||||
Total construction work in progress | 656 | 2,499 | ||||||
Property, plant and equipment — net | $ | 20,366 | $ | 30,108 | ||||
| (a) | See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010. |
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Depreciation expense totaled $1.255 billion, $1.454 billion and $1.355 billion for the years ended December 31, 2010, 2009 and 2008, respectively, including $394 million and $330 million for the years ended December 31, 2009 and 2008, respectively, related to Oncor.
We began depreciating two completed lignite-fueled generation units in the fourth quarter 2009 and the third new unit in the second quarter 2010.
Assets related to capitalized leases included above totaled $82 million and $167 million as of December 31, 2010 and 2009, respectively, net of accumulated depreciation.
Asset Retirement Obligations
These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to the recognition of the asset retirement costs for nuclear decommissioning, as all costs are recoverable through the regulatory process as part of Oncor’s rates.
The following table summarizes the changes to the asset retirement liability, reported in other current liabilities and other noncurrent liabilities and deferred credits in the balance sheet, during the years ended December 31, 2010 and 2009:
Asset retirement liability as of January 1, 2009 | $ | 859 | ||
Additions: | ||||
Accretion | 59 | |||
Incremental mining reclamation costs | 59 | |||
Reductions: | ||||
Payments, essentially all mining reclamation | (29 | ) | ||
Asset retirement liability as of December 31, 2009 | $ | 948 | ||
Additions: | ||||
Accretion | 57 | |||
Reductions: | ||||
Payments, essentially all mining reclamation | (48 | ) | ||
Adjustment for new cost estimate (a) | (464 | ) | ||
Asset retirement liability as of December 31, 2010 | 493 | |||
Less amounts due currently | (41 | ) | ||
Noncurrent asset retirement liability as of December 31, 2010 | $ | 452 | ||
| (a) | Essentially all of the adjustment relates to the nuclear decommissioning liability, which resulted from a new cost estimate completed in the second quarter 2010. In accordance with regulatory requirements, a new cost estimate is completed every five years. A decline in the liability was driven by lower cost escalation assumptions in the new estimate. The reduction in the liability was offset in part by a reduction in the carrying value of the nuclear facility with the balance offset by an increase in the noncurrent liability to Oncor, which in turn resulted in a regulatory liability on Oncor’s balance sheet. (Also see Note 22.) |
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Oncor’s Regulatory Assets and Liabilities
Recognition of regulatory assets and liabilities and the amortization periods over which they are expected to be recovered or refunded through rate regulation reflect the decisions of the PUCT. Components of the regulatory assets and liabilities are provided in the table below. Amounts not earning a return through rate regulation are noted. On August 31, 2009, the PUCT issued a final order on Oncor’s rate review filed in June 2008. The rate review included a determination of the recoverability of regulatory assets as of December 31, 2007, including the recoverability period of those assets deemed allowable by the PUCT. The PUCT’s findings included denial of recovery of certain regulatory assets primarily related to business restructuring costs and rate case expenses, which resulted in a $25 million charge ($16 million after-tax) in the third quarter 2009 reported in other deductions in the Regulated Delivery segment.
Remaining Rate December 31, 2009 | Carrying Amount | |||||
| December 31, 2009 | ||||||
Regulatory assets: | ||||||
Generation-related regulatory assets securitized by transition bonds (a) | 7 years | $ | 759 | |||
Employee retirement costs | 5 years | 80 | ||||
Employee retirement costs to be reviewed (b)(c) | To be determined | 41 | ||||
Employee retirement liability (a)(c)(d) | To be determined | 768 | ||||
Self-insurance reserve (primarily storm recovery costs) — net | 7 years | 137 | ||||
Self-insurance reserve to be reviewed (b)(c) | To be determined | 106 | ||||
Nuclear decommissioning cost under-recovery (a)(c)(e) | Not applicable | 85 | ||||
Securities reacquisition costs (pre-industry restructure) | 8 years | 62 | ||||
Securities reacquisition costs (post-industry restructure) | Terms of related debt | 27 | ||||
Recoverable amounts for/in lieu of deferred income taxes — net | Life of related asset or liability | 68 | ||||
Rate case expenses (f) | Largely 3 years | 9 | ||||
Rate case expenses to be reviewed (b)(c) | To be determined | 1 | ||||
Advanced meter customer education costs | 10 years | 4 | ||||
Deferred conventional meter depreciation | 10 years | 14 | ||||
Energy efficiency performance bonus | 1 year | 9 | ||||
Business restructuring costs (g) | Not applicable | — | ||||
Total regulatory assets | 2,170 | |||||
Regulatory liabilities: | ||||||
Committed spending for demand-side management initiatives (a) | 3 years | 78 | ||||
Deferred advanced metering system revenues | 10 years | 57 | ||||
Investment tax credit and protected excess deferred taxes | Various | 44 | ||||
Over-collection of securitization (transition) bond revenues (a) | 7 years | 27 | ||||
Other regulatory liabilities (a) | Various | 5 | ||||
Total regulatory liabilities | 211 | |||||
Net regulatory asset | $ | 1,959 | ||||
| (a) | Not earning a return in the regulatory rate-setting process. |
| (b) | Costs incurred since the period covered under the last rate review. |
| (c) | Recovery is specifically authorized by statute, subject to reasonableness review by the PUCT. |
| (d) | Represents unfunded liabilities recorded in accordance with pension and OPEB accounting standards. |
| (e) | Offset by an intercompany payable to TCEH. |
| (f) | Rate case expenses totaling $4 million were disallowed by the PUCT and written off in the third quarter 2009. |
| (g) | All previously recorded business restructuring costs were disallowed by the PUCT and written off in the third quarter 2009. |
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As part of purchase accounting, the carrying value of the generation-related regulatory assets was reduced by $213 million, and this amount is being accreted to other income over the approximate nine-year recovery period remaining as of the date of the Merger.
In September 2008, the PUCT approved a settlement for Oncor to recover its estimated future investment for advanced metering deployment. Oncor began billing the advanced metering surcharge in the January 2009 billing month cycle. The surcharge is expected to total $1.023 billion over the 11-year recovery period and includes a cost recovery factor of $2.19 per month per residential retail customer and $2.39 to $5.15 per month for non-residential retail customers. Oncor accounts for the difference between the surcharge billings for advanced metering facilities and the allowed revenues under the surcharge provisions, which are based on expenditures and an allowed return, as a regulatory asset or liability. Such differences arise principally as a result of timing of expenditures. As indicated in the table above, the regulatory liability at December 31, 2009 totaled $57 million.
See Note 6 for discussion of effects on regulatory assets and liabilities of the stipulation approved by the PUCT and Note 18 for additional information regarding nuclear decommissioning cost recovery.
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
Uncertain tax positions (including accrued interest) (Note 7) | $ | 1,806 | $ | 1,999 | ||||
Retirement plan and other employee benefits | 1,895 | 1,711 | ||||||
Asset retirement obligations | 452 | 948 | ||||||
Unfavorable purchase and sales contracts | 673 | 700 | ||||||
Liabilities related to subsidiary tax sharing agreement (a) | — | 321 | ||||||
Other | 41 | 87 | ||||||
Total other noncurrent liabilities and deferred credits | $ | 4,867 | $ | 5,766 | ||||
| (a) | See Notes 1 and 3 for discussion of the deconsolidation of Oncor Holdings effective as of January 1, 2010. |
Unfavorable Purchase and Sales Contracts — Unfavorable purchase and sales contracts primarily represent the extent to which contracts on a net basis were unfavorable to market prices as of the date of the Merger. These are contracts for which: (i) TCEH has made the “normal” purchase or sale election allowed or (ii) the contract did not meet the definition of a derivative under accounting standards related to derivative instruments and hedging transactions. Under purchase accounting, TCEH recorded the value as of October 10, 2007 as a deferred credit. Amortization of the deferred credit related to unfavorable contracts is primarily on a straight-line basis, which approximates the economic realization, and is recorded as revenues or a reduction of purchased power costs as appropriate. The amortization amount totaled $27 million, $27 million and $30 million in 2010, 2009 and 2008, respectively. Favorable purchase and sales contracts are recorded as intangible assets (see Note 4).
The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:
Year | Amount | |||
2011 | $ | 27 | ||
2012 | 27 | |||
2013 | 26 | |||
2014 | 25 | |||
2015 | 25 | |||
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Liabilities Related to Subsidiary Tax Sharing Agreement —Amount represents the previously recorded net deferred tax liabilities of Oncor related to the noncontrolling interests. Upon the sale of noncontrolling interests in Oncor (see Note 14), Oncor became a partnership for US federal income tax purposes, and the temporary differences that gave rise to the deferred taxes will, over time, become taxable to the noncontrolling interests. Under a tax sharing agreement among Oncor and its equity holders, Oncor reimburses the equity holders for federal income taxes as the partnership earnings become taxable to such holders. Accordingly, as the temporary differences become taxable, the equity holders will be reimbursed by Oncor. In the unlikely event such amounts are not reimbursed under the tax sharing agreement, it is probable they would be refunded to rate payers.
Supplemental Cash Flow Information
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Cash payments (receipts) related to: | ||||||||||||
Interest paid (a) | $ | 2,693 | $ | 2,972 | $ | 3,495 | ||||||
Capitalized interest | (60 | ) | (277 | ) | (311 | ) | ||||||
Interest paid (net of capitalized interest) (a) | �� | 2,633 | 2,695 | 3,184 | ||||||||
Income taxes | 64 | (42 | ) | (204 | ) | |||||||
Noncash investing and financing activities: | ||||||||||||
Noncash construction expenditures (b) | 84 | 197 | 183 | |||||||||
Capital leases | 9 | 15 | 16 | |||||||||
Gain on termination of long-term power sales contract (Note 9) | (116 | ) | — | — | ||||||||
| (a) | Net of interest received on interest rate swaps. |
| (b) | Represents end-of-period accruals. |
See Note 11 for noncash exchanges of debt and issuance of toggle notes in lieu of cash interest.
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| 25. | SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION |
As of December 31, 2010, EFH Corp. had outstanding $359 million principal amount of EFH Corp. 10.875% Notes and $571 million principal amount of EFH Corp. Toggle Notes (collectively, the EFH Corp. Senior Notes) and $115 million principal amount of EFH Corp. 9.75% Notes and $1.061 billion principal amount of EFH Corp. 10% Notes (collectively, the EFH Corp. Senior Secured Notes). The EFH Corp. Senior Notes and Senior Secured Notes are unconditionally guaranteed by EFCH and EFIH, 100% owned subsidiaries of EFH Corp. (collectively, the Guarantors) on an unsecured basis except for EFIH’s guarantee of the EFH Corp. Senior Secured Notes, which is secured by a pledge of all membership interests and other investments EFIH owns or holds in Oncor Holdings or any of Oncor Holdings’ subsidiaries as described in Note 11. The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the EFH Corp. Senior Notes and Senior Secured Notes. The guarantees by EFCH and the guarantee of the EFH Corp. Senior Notes by EFIH rank equally with any senior unsecured indebtedness of the Guarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. All other subsidiaries of EFH Corp., either direct or indirect, do not guarantee the EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes (collectively, the Non-Guarantors). The indentures governing the EFH Corp. Senior Notes and EFH Corp. Senior Secured Notes contain certain restrictions, subject to certain exceptions, on EFH Corp.’s ability to pay dividends or make investments. See Note 13.
The following tables have been prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered” in order to present the condensed consolidating statements of income and cash flows of EFH Corp. (the Parent/Issuer), the Guarantors and the Non-Guarantors for the years ended December 31, 2010, 2009 and 2008 and the consolidating balance sheets as of December 31, 2010 and 2009 of the Parent/Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5-J, “Push Down Basis of Accounting Required in Certain Limited Circumstances,” including the effects of the push down of the $930 million and $4.63 billion principal amount of EFH Corp. Senior Notes and $771 million and $115 million principal amount of the EFH Corp. Senior Secured Notes to the Guarantors as of December 31, 2010 and 2009, respectively (see Note 11). Amounts pushed down reflect Merger-related debt and additional debt guaranteed by the Guarantors that was issued by EFH Corp. to refinance Merger-related or other debt existing at the time of the Merger.
EFH Corp. (Parent) received dividends/distributions from its consolidated subsidiaries totaling $2 million, $216 million and $329 million for the years ended December 31, 2010, 2009 and 2008, respectively. EFH Corp. also received a distribution of $1.253 billion indirectly from Oncor in 2008 as discussed in Note 14.
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Income (Loss)
For the Year Ended December 31, 2010
(Millions of Dollars)
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | ||||||||||||||||
Operating revenues | $ | — | $ | — | $ | 8,235 | $ | — | $ | 8,235 | ||||||||||
Fuel, purchased power costs and delivery fees | — | — | (4,371 | ) | — | (4,371 | ) | |||||||||||||
Net gain from commodity hedging and trading activities | — | — | 2,161 | — | 2,161 | |||||||||||||||
Operating costs | — | — | (837 | ) | — | (837 | ) | |||||||||||||
Depreciation and amortization | — | — | (1,407 | ) | — | (1,407 | ) | |||||||||||||
Selling, general and administrative expenses | (32 | ) | — | (719 | ) | — | (751 | ) | ||||||||||||
Franchise and revenue-based taxes | — | — | (106 | ) | — | (106 | ) | |||||||||||||
Impairment of goodwill | — | — | (4,100 | ) | — | (4,100 | ) | |||||||||||||
Other income | 137 | — | 920 | 994 | 2,051 | |||||||||||||||
Other deductions | — | — | (33 | ) | 2 | (31 | ) | |||||||||||||
Interest income | 178 | 209 | 327 | (704 | ) | 10 | ||||||||||||||
Interest expense and related charges | (1,082 | ) | (545 | ) | (3,057 | ) | 1,130 | (3,554 | ) | |||||||||||
Income (loss) before income taxes and equity in earnings of subsidiaries | (799 | ) | (336 | ) | (2,987 | ) | 1,422 | (2,700 | ) | |||||||||||
Income tax (expense) benefit | 305 | 125 | (309 | ) | (510 | ) | (389 | ) | ||||||||||||
Equity in earnings of consolidated subsidiaries | (2,595 | ) | (3,383 | ) | — | 5,978 | — | |||||||||||||
Equity in earnings of unconsolidated subsidiaries (net of tax) | 277 | 277 | — | (277 | ) | 277 | ||||||||||||||
Net loss | (2,812 | ) | (3,317 | ) | (3,296 | ) | 6,613 | (2,812 | ) | |||||||||||
Net (income) loss attributable to noncontrolling interests | — | — | — | — | — | |||||||||||||||
Net loss attributable to EFH Corp. | $ | (2,812 | ) | $ | (3,317 | ) | $ | (3,296 | ) | $ | 6,613 | $ | (2,812 | ) | ||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Income
For the Year Ended December 31, 2009
(Millions of Dollars)
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | ||||||||||||||||
Operating revenues | $ | — | $ | — | $ | 9,546 | $ | — | $ | 9,546 | ||||||||||
Fuel, purchased power costs and delivery fees | — | — | (2,878 | ) | — | (2,878 | ) | |||||||||||||
Net gain from commodity hedging and trading activities | — | — | 1,736 | — | 1,736 | |||||||||||||||
Operating costs | — | — | (1,598 | ) | — | (1,598 | ) | |||||||||||||
Depreciation and amortization | — | — | (1,754 | ) | — | (1,754 | ) | |||||||||||||
Selling, general and administrative expenses | (123 | ) | — | (945 | ) | — | (1,068 | ) | ||||||||||||
Franchise and revenue-based taxes | — | — | (359 | ) | — | (359 | ) | |||||||||||||
Impairment of goodwill | — | — | (90 | ) | — | (90 | ) | |||||||||||||
Other income | 49 | — | 114 | 41 | 204 | |||||||||||||||
Other deductions | (6 | ) | — | (91 | ) | — | (97 | ) | ||||||||||||
Interest income | 235 | 5 | 149 | (344 | ) | 45 | ||||||||||||||
Interest expense and related charges | (981 | ) | (570 | ) | (2,258 | ) | 897 | (2,912 | ) | |||||||||||
Income (loss) before income taxes and equity earnings of subsidiaries | (826 | ) | (565 | ) | 1,572 | 594 | 775 | |||||||||||||
Income tax (expense) benefit | 268 | 188 | (622 | ) | (201 | ) | (367 | ) | ||||||||||||
Equity earnings of subsidiaries | 902 | 965 | — | (1,867 | ) | — | ||||||||||||||
Net income | 344 | 588 | 950 | (1,474 | ) | 408 | ||||||||||||||
Net income attributable to noncontrolling interests | — | — | (64 | ) | — | (64 | ) | |||||||||||||
Net income attributable to EFH Corp. | $ | 344 | $ | 588 | $ | 886 | $ | (1,474 | ) | $ | 344 | |||||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Income (Loss)
For the Year Ended December 31, 2008
(Millions of Dollars)
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | ||||||||||||||||
Operating revenues | $ | — | $ | — | $ | 11,364 | $ | — | $ | 11,364 | ||||||||||
Fuel, purchased power costs and delivery fees | — | — | (4,595 | ) | — | (4,595 | ) | |||||||||||||
Net gain from commodity hedging and trading activities | — | — | 2,184 | — | 2,184 | |||||||||||||||
Operating costs | — | — | (1,503 | ) | — | (1,503 | ) | |||||||||||||
Depreciation and amortization | — | — | (1,610 | ) | — | (1,610 | ) | |||||||||||||
Selling, general and administrative expenses | (105 | ) | — | (852 | ) | — | (957 | ) | ||||||||||||
Franchise and revenue-based taxes | — | 1 | (364 | ) | — | (363 | ) | |||||||||||||
Impairment of goodwill | — | — | (8,860 | ) | — | (8,860 | ) | |||||||||||||
Other income | — | — | 80 | — | 80 | |||||||||||||||
Other deductions | (22 | ) | — | (1,279 | ) | — | (1,301 | ) | ||||||||||||
Interest income | 168 | 7 | 147 | (295 | ) | 27 | ||||||||||||||
Interest expense and related charges | (919 | ) | (537 | ) | (4,298 | ) | 819 | (4,935 | ) | |||||||||||
Income (loss) before income taxes and equity earnings of subsidiaries | (878 | ) | (529 | ) | (9,586 | ) | 524 | (10,469 | ) | |||||||||||
Income tax (expense) benefit | 291 | 180 | 176 | (176 | ) | 471 | ||||||||||||||
Equity earnings of subsidiaries | (9,251 | ) | (9,184 | ) | — | 18,435 | — | |||||||||||||
Net loss | (9,838 | ) | (9,533 | ) | (9,410 | ) | 18,783 | (9,998 | ) | |||||||||||
Net loss attributable to noncontrolling interests | — | — | 160 | — | 160 | |||||||||||||||
Net loss attributable to EFH Corp. | $ | (9,838 | ) | $ | (9,533 | ) | $ | (9,250 | ) | $ | 18,783 | $ | (9,838 | ) | ||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2010
(Millions of Dollars)
| Parent/Issuer | Guarantors | Non-guarantors | Eliminations | Consolidated | ||||||||||||||||
Cash provided by operating activities | $ | 168 | $ | 111 | $ | 835 | $ | (8 | ) | $ | 1,106 | |||||||||
Cash flows — financing activities: | ||||||||||||||||||||
Issuances of long-term borrowings | 500 | — | 353 | — | 853 | |||||||||||||||
Repayments/repurchases of long-term borrowings | (96 | ) | (8 | ) | (642 | ) | (605 | ) | (1,351 | ) | ||||||||||
Net short-term borrowings under accounts receivable securitization program | — | — | 96 | — | 96 | |||||||||||||||
Change in other short-term borrowings | — | — | 172 | — | 172 | |||||||||||||||
Capital contribution from parent | — | 440 | — | (440 | ) | — | ||||||||||||||
Contributions from noncontrolling interests | — | — | 32 | — | 32 | |||||||||||||||
Cash dividends paid | — | (2 | ) | — | 2 | — | ||||||||||||||
Repayment of note — affiliate | 770 | — | (770 | ) | — | — | ||||||||||||||
Change in notes/advances — affiliates | (785 | ) | 33 | 733 | (18 | ) | (37 | ) | ||||||||||||
Other, net | (28 | ) | (31 | ) | 24 | 6 | (29 | ) | ||||||||||||
Cash provided by (used in) financing activities | 361 | 432 | (2 | ) | (1,055 | ) | (264 | ) | ||||||||||||
Cash flows — investing activities: | ||||||||||||||||||||
Capital expenditures and nuclear fuel purchases | — | — | (944 | ) | — | (944 | ) | |||||||||||||
Capital contribution to subsidiary | (440 | ) | — | — | 440 | — | ||||||||||||||
Investment in affiliate debt | (105 | ) | (500 | ) | — | 605 | — | |||||||||||||
Investment redeemed from derivative counterparty | 400 | — | — | — | 400 | |||||||||||||||
Proceeds from sale of assets | — | — | 147 | — | 147 | |||||||||||||||
Proceeds from sale of environmental allowances and credits | — | — | 12 | — | 12 | |||||||||||||||
Purchases of environmental allowances and credits | — | — | (30 | ) | — | (30 | ) | |||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | — | — | 974 | — | 974 | |||||||||||||||
Investments in nuclear decommissioning trust fund securities | — | — | (990 | ) | — | (990 | ) | |||||||||||||
Change in notes/advances — affiliates | — | — | (18 | ) | 18 | — | ||||||||||||||
Other, net | — | — | (37 | ) | — | (37 | ) | |||||||||||||
Cash used in investing activities | (145 | ) | (500 | ) | (886 | ) | 1,063 | (468 | ) | |||||||||||
Net change in cash and cash equivalents | 384 | 43 | (53 | ) | — | 374 | ||||||||||||||
Effects of deconsolidation of Oncor Holdings | — | — | (29 | ) | — | (29 | ) | |||||||||||||
Cash and cash equivalents — beginning balance | 1,059 | — | 130 | — | 1,189 | |||||||||||||||
Cash and cash equivalents — ending balance | $ | 1,443 | $ | 43 | $ | 48 | $ | — | $ | 1,534 | ||||||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2009
(Millions of Dollars)
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | ||||||||||||||||
Cash provided by (used in) operating activities | $ | (42 | ) | $ | 208 | $ | 1,977 | $ | (432 | ) | $ | 1,711 | ||||||||
Cash flows — financing activities: | ||||||||||||||||||||
Issuances of long-term borrowings | — | — | 522 | — | 522 | |||||||||||||||
Retirements of long-term borrowings | (4 | ) | (7 | ) | (385 | ) | — | (396 | ) | |||||||||||
Change in short-term borrowings | — | — | 332 | — | 332 | |||||||||||||||
Contributions from noncontrolling interests | — | — | 48 | — | 48 | |||||||||||||||
Distributions paid to noncontrolling interests | — | — | (56 | ) | — | (56 | ) | |||||||||||||
Cash dividends paid | — | (216 | ) | (216 | ) | 432 | — | |||||||||||||
Change in notes/advances — affiliates | 425 | 15 | — | (440 | ) | — | ||||||||||||||
Other, net | 5 | — | (33 | ) | — | �� | (28 | ) | ||||||||||||
Cash provided by (used in) financing activities | 426 | (208 | ) | 212 | (8 | ) | 422 | |||||||||||||
Cash flows — investing activities: | ||||||||||||||||||||
Capital expenditures and nuclear fuel purchases | — | — | (2,545 | ) | — | (2,545 | ) | |||||||||||||
Money market fund redemptions | — | — | 142 | — | 142 | |||||||||||||||
Investment posted with derivative counterparty | (400 | ) | — | — | — | (400 | ) | |||||||||||||
Proceeds from sale of assets | — | — | 42 | — | 42 | |||||||||||||||
Reduction of restricted cash related to letter of credit facility | — | — | 115 | — | 115 | |||||||||||||||
Proceeds from sale of environmental allowances and credits | — | — | 19 | — | 19 | |||||||||||||||
Purchases of environmental allowances and credits | — | — | (19 | ) | — | (19 | ) | |||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | — | — | 3,064 | — | 3,064 | |||||||||||||||
Investments in nuclear decommissioning trust fund securities | — | — | (3,080 | ) | — | (3,080 | ) | |||||||||||||
Change in notes/advances — affiliates | — | — | (440 | ) | 440 | — | ||||||||||||||
Other, net | — | — | 29 | — | 29 | |||||||||||||||
Cash used in investing activities | (400 | ) | — | (2,673 | ) | 440 | (2,633 | ) | ||||||||||||
Net change in cash and cash equivalents | (16 | ) | — | (484 | ) | — | (500 | ) | ||||||||||||
Cash and cash equivalents — beginning balance | 1,075 | — | 614 | — | 1,689 | |||||||||||||||
Cash and cash equivalents — ending balance | $ | 1,059 | $ | — | $ | 130 | $ | — | $ | 1,189 | ||||||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2008
(Millions of Dollars)
| Parent/Issuer | Guarantors | Non-guarantors | Eliminations | Consolidated | ||||||||||||||||
Cash provided by (used in) operating activities | $ | (251 | ) | $ | (924 | ) | $ | 832 | $ | 1,848 | $ | 1,505 | ||||||||
Cash flows — financing activities: | ||||||||||||||||||||
Issuances of long-term borrowings/securities: | ||||||||||||||||||||
Long-term debt | — | — | 3,185 | — | 3,185 | |||||||||||||||
Common stock | 34 | — | — | — | 34 | |||||||||||||||
Repayments/repurchases of long-term borrowings/ securities: | ||||||||||||||||||||
Long-term debt | (200 | ) | (7 | ) | (960 | ) | — | (1,167 | ) | |||||||||||
Common stock | (3 | ) | — | — | — | (3 | ) | |||||||||||||
Change in short-term borrowings | — | — | (481 | ) | — | (481 | ) | |||||||||||||
Proceeds from sale of noncontrolling interests, net of transaction costs | 1,253 | 1,253 | 1,253 | (2,506 | ) | 1,253 | ||||||||||||||
Cash dividends paid | — | (329 | ) | (329 | ) | 658 | — | |||||||||||||
Change in notes/advances — affiliates | 205 | 7 | — | (212 | ) | — | ||||||||||||||
Other, net | — | — | 16 | — | 16 | |||||||||||||||
Cash provided by financing activities | 1,289 | 924 | 2,684 | (2,060 | ) | 2,837 | ||||||||||||||
Cash flows — investing activities: | ||||||||||||||||||||
Capital expenditures and nuclear fuel purchases | — | — | (2,978 | ) | — | (2,978 | ) | |||||||||||||
Money market fund investments | — | — | (142 | ) | — | (142 | ) | |||||||||||||
Proceeds from sale of environmental allowances and credits | — | — | 39 | — | 39 | |||||||||||||||
Purchases of environmental allowances and credits | — | — | (34 | ) | — | (34 | ) | |||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | — | — | 1,623 | — | 1,623 | |||||||||||||||
Investments in nuclear decommissioning trust fund securities | — | — | (1,639 | ) | — | (1,639 | ) | |||||||||||||
Change in notes/advances — affiliates | — | — | (212 | ) | 212 | — | ||||||||||||||
Other, net | 5 | — | 192 | — | 197 | |||||||||||||||
Cash provided by (used in) investing activities | 5 | — | (3,151 | ) | 212 | (2,934 | ) | |||||||||||||
Net change in cash and cash equivalents | 1,043 | — | 365 | — | 1,408 | |||||||||||||||
Cash and cash equivalents — beginning balance | 32 | — | 249 | — | 281 | |||||||||||||||
Cash and cash equivalents — ending balance | $ | 1,075 | $ | — | $ | 614 | $ | — | $ | 1,689 | ||||||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
As of December 31, 2010
(Millions of Dollars)
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | ||||||||||||||||
| ASSETS | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 1,443 | $ | 43 | $ | 48 | $ | — | $ | 1,534 | ||||||||||
Restricted cash | — | — | 33 | — | 33 | |||||||||||||||
Advances to affiliates | — | — | 219 | (219 | ) | — | ||||||||||||||
Trade accounts receivable — net | 12 | 73 | 991 | (77 | ) | 999 | ||||||||||||||
Income taxes receivable | 47 | — | — | (47 | ) | — | ||||||||||||||
Accounts receivable from affiliates | 26 | — | — | (26 | ) | — | ||||||||||||||
Notes receivable from affiliates | 165 | — | 1,921 | (2,086 | ) | — | ||||||||||||||
Inventories | — | — | 395 | — | 395 | |||||||||||||||
Commodity and other derivative contractual assets | 92 | — | 2,640 | — | 2,732 | |||||||||||||||
Accumulated deferred income taxes | — | 3 | — | (3 | ) | — | ||||||||||||||
Margin deposits related to commodity positions | — | — | 166 | — | 166 | |||||||||||||||
Other current assets | 2 | — | 58 | — | 60 | |||||||||||||||
Total current assets | 1,787 | 119 | 6,471 | (2,458 | ) | 5,919 | ||||||||||||||
Restricted cash | — | — | 1,135 | — | 1,135 | |||||||||||||||
Receivables from unconsolidated subsidiary | 1,463 | — | — | — | 1,463 | |||||||||||||||
Investments in unconsolidated subsidiaries | — | 5,544 | — | — | 5,544 | |||||||||||||||
Other investments | 2,924 | (2,300 | ) | 628 | (555 | ) | 697 | |||||||||||||
Property, plant and equipment — net | — | — | 20,366 | — | 20,366 | |||||||||||||||
Notes receivable from affiliates | 12 | — | 1,282 | (1,294 | ) | — | ||||||||||||||
Goodwill | — | — | 6,152 | — | 6,152 | |||||||||||||||
Identifiable intangible assets — net | — | — | 2,400 | — | 2,400 | |||||||||||||||
Commodity and other derivative contractual assets | — | — | 2,071 | — | 2,071 | |||||||||||||||
Accumulated deferred income taxes | 714 | — | — | (714 | ) | — | ||||||||||||||
Other noncurrent assets, principally unamortized issuance costs | 95 | 53 | 577 | (84 | ) | 641 | ||||||||||||||
Total assets | $ | 6,995 | $ | 3,416 | $ | 41,082 | $ | (5,105 | ) | $ | 46,388 | |||||||||
| LIABILITIES AND EQUITY | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Short-term borrowings | $ | — | $ | — | $ | 1,221 | $ | — | $ | 1,221 | ||||||||||
Notes/advances from affiliates | 211 | 8 | — | (219 | ) | — | ||||||||||||||
Long-term debt due currently | — | 9 | 660 | — | 669 | |||||||||||||||
Trade accounts payable | 1 | 1 | 679 | — | 681 | |||||||||||||||
Payables to affiliates/unconsolidated subsidiary | 1,921 | 46 | 326 | (2,039 | ) | 254 | ||||||||||||||
Commodity and other derivative contractual liabilities | 119 | — | 2,164 | — | 2,283 | |||||||||||||||
Margin deposits related to commodity positions | — | — | 631 | — | 631 | |||||||||||||||
Accumulated deferred income taxes | 12 | — | 2 | (3 | ) | 11 | ||||||||||||||
Accrued interest | 165 | 72 | 302 | (128 | ) | 411 | ||||||||||||||
Other current liabilities | 3 | 46 | 507 | (114 | ) | 442 | ||||||||||||||
Total current liabilities | 2,432 | 182 | 6,492 | (2,503 | ) | 6,603 | ||||||||||||||
Accumulated deferred income taxes | — | 159 | 5,738 | (547 | ) | 5,350 | ||||||||||||||
Commodity and other derivative contractual liabilities | — | — | 869 | — | 869 | |||||||||||||||
Notes or other liabilities due affiliates/unconsolidated subsidiary | 1,282 | — | 396 | (1,294 | ) | 384 | ||||||||||||||
Long-term debt, less amounts due currently | 7,286 | 4,106 | 28,617 | (5,783 | ) | 34,226 | ||||||||||||||
Other noncurrent liabilities and deferred credits | 1,985 | 12 | 2,870 | — | 4,867 | |||||||||||||||
Total liabilities | 12,985 | 4,459 | 44,982 | (10,127 | ) | 52,299 | ||||||||||||||
EFH Corp. shareholders’ equity | (5,990 | ) | (1,043 | ) | (3,987 | ) | 5,030 | (5,990 | ) | |||||||||||
Noncontrolling interests in subsidiaries | — | — | 87 | (8 | ) | 79 | ||||||||||||||
Total equity | (5,990 | ) | (1,043 | ) | (3,900 | ) | 5,022 | (5,911 | ) | |||||||||||
Total liabilities and equity | $ | 6,995 | $ | 3,416 | $ | 41,082 | $ | (5,105 | ) | $ | 46,388 | |||||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
As of December 31, 2009
(Millions of Dollars)
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | ||||||||||||||||
| ASSETS | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 1,059 | $ | — | $ | 130 | $ | — | $ | 1,189 | ||||||||||
Investment posted with counterparty | 425 | — | — | — | 425 | |||||||||||||||
Restricted cash | — | — | 48 | — | 48 | |||||||||||||||
Advances to affiliates | 471 | 5 | — | (476 | ) | — | ||||||||||||||
Trade accounts receivable — net | 8 | 2 | 1,253 | (3 | ) | 1,260 | ||||||||||||||
Income taxes receivable | 23 | 2 | — | (25 | ) | — | ||||||||||||||
Accounts receivable from affiliates | — | — | 22 | (22 | ) | — | ||||||||||||||
Notes receivable from affiliates | 114 | — | 1,469 | (1,583 | ) | — | ||||||||||||||
Inventories | — | — | 485 | — | 485 | |||||||||||||||
Commodity and other derivative contractual assets | 52 | — | 2,339 | — | 2,391 | |||||||||||||||
Accumulated deferred income taxes | — | 3 | 11 | (9 | ) | 5 | ||||||||||||||
Margin deposits related to commodity positions | — | — | 187 | — | 187 | |||||||||||||||
Other current assets | 2 | — | 134 | — | 136 | |||||||||||||||
Total current assets | 2,154 | 12 | 6,078 | (2,118 | ) | 6,126 | ||||||||||||||
Restricted cash | — | — | 1,149 | — | 1,149 | |||||||||||||||
Investments in unconsolidated subsidiaries | — | — | 44 | — | 44 | |||||||||||||||
Other investments | 4,586 | 3,634 | 638 | (8,152 | ) | 706 | ||||||||||||||
Property, plant and equipment — net | — | — | 30,108 | — | 30,108 | |||||||||||||||
Notes receivable from affiliates | 12 | — | 2,236 | (2,248 | ) | — | ||||||||||||||
Goodwill | — | — | 14,316 | — | 14,316 | |||||||||||||||
Identifiable intangible assets — net | — | — | 2,876 | — | 2,876 | |||||||||||||||
Regulatory assets — net | — | — | 1,959 | — | 1,959 | |||||||||||||||
Commodity and other derivative contractual assets | — | — | 1,533 | — | 1,533 | |||||||||||||||
Accumulated deferred income taxes | 647 | 111 | — | (758 | ) | — | ||||||||||||||
Noncurrent assets, principally unamortized debt issuance costs | 108 | 99 | 733 | (95 | ) | 845 | ||||||||||||||
Total assets | $ | 7,507 | $ | 3,856 | $ | 61,670 | $ | (13,371 | ) | $ | 59,662 | |||||||||
| LIABILITIES AND EQUITY | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Short-term borrowings | $ | — | $ | — | $ | 1,569 | $ | — | $ | 1,569 | ||||||||||
Notes/advances from affiliates | — | — | 476 | (476 | ) | — | ||||||||||||||
Long-term debt due currently | — | 8 | 409 | — | 417 | |||||||||||||||
Trade accounts payable | 4 | — | 892 | — | 896 | |||||||||||||||
Accounts payable to affiliates | 16 | 6 | — | (22 | ) | — | ||||||||||||||
Notes payable to affiliates | 1,406 | 27 | 150 | (1,583 | ) | — | ||||||||||||||
Commodity and other derivative contractual liabilities | 82 | — | 2,310 | — | 2,392 | |||||||||||||||
Margin deposits related to commodity positions | — | — | 520 | — | 520 | |||||||||||||||
Accumulated deferred income taxes | 9 | — | — | (9 | ) | — | ||||||||||||||
Accrued interest | 119 | 93 | 408 | (94 | ) | 526 | ||||||||||||||
Other current liabilities | 7 | — | 761 | (24 | ) | 744 | ||||||||||||||
Total current liabilities | 1,643 | 134 | 7,495 | (2,208 | ) | 7,064 | ||||||||||||||
Accumulated deferred income taxes | — | — | 6,764 | (633 | ) | 6,131 | ||||||||||||||
Investment tax credits | — | — | 37 | — | 37 | |||||||||||||||
Commodity and other derivative contractual liabilities | — | — | 1,060 | — | 1,060 | |||||||||||||||
Notes or other liabilities due affiliates | 2,019 | — | 229 | (2,248 | ) | — | ||||||||||||||
Long-term debt, less amounts due currently | 6,626 | 4,975 | 34,740 | (4,901 | ) | 41,440 | ||||||||||||||
Other noncurrent liabilities and deferred credits | 466 | 3 | 5,297 | — | 5,766 | |||||||||||||||
Total liabilities | 10,754 | 5,112 | 55,622 | (9,990 | ) | 61,498 | ||||||||||||||
EFH Corp. shareholders’ equity | (3,247 | ) | (1,256 | ) | 4,637 | (3,381 | ) | (3,247 | ) | |||||||||||
Noncontrolling interests in subsidiaries | — | — | 1,411 | — | 1,411 | |||||||||||||||
Total equity | (3,247 | ) | (1,256 | ) | 6,048 | (3,381 | ) | (1,836 | ) | |||||||||||
Total liabilities and equity | $ | 7,507 | $ | 3,856 | $ | 61,670 | $ | (13,371 | ) | $ | 59,662 | |||||||||
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| Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| Item 9A. | CONTROLS AND PROCEDURES |
An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect as of December 31, 2010. Based on the evaluation performed, our management, including the principal executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective.
There has been no change in our internal control over financial reporting during the most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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ENERGY FUTURE HOLDINGS CORP.
MANAGEMENT’S ANNUAL REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Energy Future Holdings Corp. is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Energy Future Holdings Corp.’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in condition or the deterioration of compliance with procedures or policies.
The management of Energy Future Holdings Corp. performed an evaluation as of December 31, 2010 of the effectiveness of the company’s internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission’s (COSO’s)Internal Control—Integrated Framework. Based on the review performed, management believes that as of December 31, 2010 Energy Future Holdings Corp.’s internal control over financial reporting was effective.
The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial statements of Energy Future Holdings Corp. has issued an attestation report on Energy Future Holdings Corp.’s internal control over financial reporting.
/s/ JOHN F. YOUNG | /s/ PAUL M. KEGLEVIC | |||
| John F. Young, President and | Paul M. Keglevic, Executive Vice President | |||
| Chief Executive Officer | and Chief Financial Officer |
February 17, 2011
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Energy Future Holdings Corp.
Dallas, Texas
We have audited the internal control over financial reporting of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) as of December 31, 2010 based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. EFH Corp.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on EFH Corp.’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, EFH Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of December 31, 2010 and for the year ended December 31, 2010 of EFH Corp. and our report dated February 17, 2011 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding EFH Corp’s adoption of amended consolidation accounting standards related to variable interest entities and EFH Corp.’s adoption of amended guidance regarding transfers of financial assets effective January 1, 2010, on a prospective basis.
| /s/ Deloitte & Touche LLP |
| Dallas, Texas |
| February 17, 2011 |
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| Item 9B. | OTHER INFORMATION |
On February 15, 2011, the Organization and Compensation Committee (O&C Committee) of the Board approved several modifications to our executive officers’ compensation arrangements, including certain amendments to their employment agreements. After considering relevant market data and other pertinent considerations, the O&C Committee made these modifications to provide additional incentives to ensure strong performance and retention, and to maintain alignment between our executive officers and our shareholders.
Long Term Cash Incentive Awards
The O&C Committee approved a modification to the retention incentive awards that were granted to the Named Executive Officers in October 2009 (February 2010, with respect to Mr. Young). Under the terms of the original retention incentive award, each of the Named Executive Officers will be entitled to receive on September 30, 2012, to the extent such Named Executive Officer remains employed by EFH Corp. on such date, a one-time, lump-sum cash payment equal to 75% (100% with respect to Mr. Young) of the aggregate AIP award received by such executive officer for fiscal years 2009, 2010 and 2011 (the Initial LTI Award). As modified, the Initial LTI Award will include an additional amount (such additional amount, the 2011 LTI Award) of between $650,000.00 and $1,300,000.00 ($750,000.00 and $1,500,000.00 with respect to Mr. Young), which is only payable if the executive is paid the full Initial LTI Award. The actual amount of the 2011 LTI Award will be determined (subject to interpolation) by company performance as indicated by the level of management EBITDA actually achieved for the fiscal year ended December 31, 2011 relative to the management EBITDA threshold and target amounts set by the O&C Committee for the fiscal year ended December 31, 2011. Provided that the executive remains employed by EFH Corp. on such dates, half of the 2011 LTI Award will be deferred and paid on September 30, 2012, and the other half of the 2011 LTI Award will be deferred and paid on September 30, 2013.
In addition, each of the Named Executive Officers will be entitled to receive additional retention incentive awards (collectively, the 2014 LTI Award) as follows:
| • | An award of between $500,000 and $1,000,000 ($1,350,000 and $2,700,000 with respect to Mr. Young), with the actual amount of the award to be determined (subject to interpolation) by company performance as indicated by the level of management EBITDA actually achieved for the fiscal year ended December 31, 2012 relative to the management EBITDA threshold and target amounts set by the O&C Committee for the fiscal year ended December 31, 2012; and |
| • | An award of between $500,000 and $1,000,000 ($1,350,000 and $2,700,000 with respect to Mr. Young), with the actual amount of the award to be determined (subject to interpolation) by company performance as indicated by the level of management EBITDA actually achieved for the fiscal year ended December 31, 2013 relative to the management EBITDA threshold and target amounts set by the O&C Committee for the fiscal year ended December 31, 2013; and |
| • | An award of between $500,000 and $1,000,000 ($1,350,000 and $2,700,000 with respect to Mr. Young), with the actual amount of the award to be determined (subject to interpolation) by company performance as indicated by the level of management EBITDA actually achieved for the fiscal year ended December 31, 2014 relative to the management EBITDA threshold and target amounts set by the O&C Committee for the fiscal year ended December 31, 2014. |
Payment of the 2014 LTI Award will be deferred until March 13, 2015, and will be subject to the condition that the Named Executive Officer continues to be employed by EFH Corp. on such date. Both the 2011 LTI Award and the 2014 LTI Award will be subject, in limited circumstances, to acceleration and/or pro-ration in the event of the Named Executive Officer’s termination without “cause” or resignation for “good reason,” or in the event of such Named Executive Officer’s death or disability, as described in greater detail in the Named Executive Officer’s amended employment agreement.
Exchange of Stock Options for Restricted Stock Units
The O&C Committee also approved an exchange program, pursuant to which each of its executive officers, including the Named Executive Officers, would be entitled to receive a one-time lump sum grant of restricted stock units that cliff-vest 100% on September 30, 2014 (the Exchange RSUs) under and subject to the terms of the 2007 Stock Incentive Plan for Key Employees of EFH Corp. and Affiliates (the 2007 Plan), in exchange for forfeiting all rights in respect of any and all options to purchase shares of EFH Corp.’s common stock that were granted to the executive officers under the 2007 Plan as set forth below:
Executive Officer | Surrendered Options | Exchange RSUs | ||
John F. Young | 9,000,000 | 4,500,000 | ||
Paul M. Keglevic | 3,000,000 | 1,500,000 | ||
David A. Campbell | 4,800,000 | 2,400,000 | ||
James A. Burke | 2,650,000 | 1,325,000 | ||
M.A. McFarland | 2,400,000 | 1,200,000 | ||
The grant of Exchange RSUs will be made as soon as reasonably practical following an exchange period, and will be evidenced by a written agreement that is approved by the O&C Committee with the concurrence of the executive officer.
Annual Grant of RSUs:
In addition, under the terms of their amended employment agreements, the Company’s executive officers, including each of the Named Executive Officers, will be entitled to receive annual grants of restricted stock units (the Annual RSUs) under and subject to the terms of the 2007 Plan, in each of 2011, 2012 and 2013. For the Named Executive Officers, the grant of Annual RSUs for each of the 2011, 2012 and 2013 calendar years will consist of 500,000 cliff-vesting restricted stock units (666,667 with respect to Mr. Campbell and 1,500,000 with respect to Mr. Young) that will vest 100% on September 30, 2014. The initial Annual RSU grant for 2011 will be made as soon as reasonably practical, and the annual awards for 2012 and 2013 will be made following, and in connection with such year’s February meeting of the O&C Committee.
The Annual RSU awards will be subject to such terms, conditions and restrictions contained in the executive officer’s amended employment agreement, including, but not limited to, a provision that if there is a Change in Control (as that term is defined in the agreement) of EFH Corp., all ungranted Annual RSUs that would have been made to the executive in each of 2011, 2012 and 2013 will be immediately granted and vested.
| Item 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Directors
The names of EFH Corp.’s directors and information about them, as furnished by the directors themselves, are set forth below:
Name | Age | Served As | Business Experience | |||
| Arcilia C. Acosta (1)(4) | 45 | 2008 | Arcilia C. Acosta has served as a Director of EFH Corp. since May 2008. During the last seven years, Ms. Acosta’s principal occupation and employment has been serving as the CEO of CARCON Industries & Construction, L.L.C. (CARCON) and its subsidiaries. She is also the CEO of Southwestern Testing Laboratories, L.L.C. (STL). CARCON’s principal business is commercial, institutional and transportation construction. STL’s principal business is geotechnical engineering, construction materials testing and environmental consulting. Ms. Acosta is a former Chair of the State of Texas Hispanic chambers organization known as the Texas Association of Mexican American Chambers of Commerce (TAMACC) and the Greater Dallas Hispanic Chamber of Commerce. Ms. Acosta serves on the Board of Advisors for BBVA Compass Bank and the Board of Directors of the Dallas Citizens Council. | |||
| David Bonderman | 68 | 2007 | David Bonderman has served as a Director of EFH Corp. since October 2007. He is a founding partner of TPG Capital, L.P. (TPG). Mr. Bonderman serves on the boards of the following companies: Armstrong World Industries, Inc., Ceasars Entertainment Corporation (formerly Harrahs’s Entertainment), CoStar Group, Inc., General Motors Company, Ryanair Holdings plc, for which he serves as Chairman of the Board, and Univision Communications, Inc. During the past five years, Mr. Bonderman also served on the boards of Burger King Corporation, Burger King Holdings, Inc., Ducati Motor Holding S.P.A., Gemplus International S.A. (predecessor to Gemalto N.V.), Gemalto N.V., IASIS Healthcare Corporation, and Washington Mutual, Inc. | |||
| Donald L. Evans (2)(3)(4) | 64 | 2007 | Donald L. Evans has served as a Director and Non-Executive Chairman of EFH Corp. since October 2007. He is also a Senior Partner at Quintana Energy Partners, L.P. He was CEO of the Financial Services Forum from 2005 to 2007, after serving as the 34th secretary of the U.S. Department of Commerce. Before serving as Secretary of Commerce, Mr. Evans was the former CEO of Tom Brown, Inc., a large independent energy company. He also previously served as a member and chairman of the Board of Regents of the University of Texas System. | |||
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Name | Age | Served As | Business Experience | |||
| Thomas D. Ferguson (3) | 57 | 2008 | Thomas D. Ferguson has served as a Director of EFH Corp. since December 2008. He is a Managing Director of Goldman, Sachs & Co., having joined the firm in 2002. Mr. Ferguson heads the asset management efforts for the merchant bank’s U.S. real estate and infrastructure investment activity. He currently serves on the board of Carrix, one of the largest private container terminal operators in the world, American Golf, for which he serves as the company’s non-executive Chairman, Agriculture Company of America, EFIH and Oncor. He formerly held board seats at Associated British Ports, the largest port company in the UK, as well as Red de Carreteras, a toll road concessionaire in Mexico. | |||
| Frederick M. Goltz (2)(3) | 39 | 2007 | Frederick M. Goltz has served as a Director of EFH Corp. since October 2007. He has been with Kohlberg Kravis Roberts and Co., L.P. (KKR) for 15 years. Mr. Goltz has played a significant role in the development of many of the themes pursued by KKR in the energy space, including those related to integrated utilities, merchant generation, and oil and gas exploration and production. He now heads KKR’s Mezzanine Fund headquartered in San Francisco. He is a director of EFCH and TCEH. During the past five years, Mr. Goltz also served on the boards of Accuride Corp. and Texas Genco Holdings, Inc. | |||
| James R. Huffines (1)(3) | 59 | 2007 | James R. Huffines has served as a Director of EFH Corp. since October 2007. He is President and Chief Operating Officer of PlainsCapital Corporation, a $5.5 billion bank and financial service firm. He previously served as Chairman, Central and South Texas Region, of PlainsCapital Bank and Senior Executive Vice President of Plains Capital Corporation from March 2001 to November 2010, Chairman of the University of Texas System Board of Regents from April 2009 to July 2010, Vice Chairman from November 2007 to April 2009 and Chairman from June 2004 to November 2007. Mr. Huffines is a director of Andrew Harper Travel Publications, Inc., EFIH and PlainsCapital Bank. | |||
| Scott Lebovitz | 35 | 2007 | Scott Lebovitz has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area since 2007 having joined Goldman, Sachs & Co. in 1997. Mr. Lebovitz serves on the boards of both public and private companies, including CVR Energy, Inc., EFCH and TCEH. | |||
| Jeffrey Liaw | 34 | 2007 | Jeffrey Liaw has served as a Director of EFH Corp. since October 2007. He is a principal of TPG and is active in TPG’s energy and industrial investing practice areas. Before joining TPG in 2005, he worked for Bain Capital in its industrials practice. Mr. Liaw serves on the boards of both public and private companies, including EFIH, Graphic Packaging Holding Company, American Tire Distributors, Inc. and Oncor. | |||
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Name | Age | Served As | Business Experience | |||
| Marc S. Lipschultz (4) | 42 | 2007 | Marc S. Lipschultz has served as a Director of EFH Corp. since October 2007. He joined KKR in 1995 and is the global head of KKR’s Energy and Infrastructure business. Mr. Lipschultz serves on KKR’s Management Committee and its Infrastructure Investment Committee. Currently, he is on the board of Accel-KKR Company. During the past five years, Mr. Lipschultz also served on the boards of Texas Genco Holdings, Inc. and The Boyds Collection, Ltd.. | |||
| Michael MacDougall (2)(3) | 40 | 2007 | Michael MacDougall has served as a Director of EFH Corp. since October 2007. He is a partner of TPG. Mr. MacDougall leads the firm’s global energy and natural resources investing efforts. Prior to joining TPG in 2002, Mr. MacDougall was a vice president in the Principal Investment Area of the Merchant Banking Division of Goldman, Sachs & Co., where he focused on private equity and mezzanine investments. Mr. MacDougall is a director of both public and private companies, including Copano Energy, L.L.C., Graphic Packaging Holding Company, Harvester Holdings, LLC and its two subsidiaries, Petro Harvester Oil and Gas, LLC and 2CO Energy Limited, Kraton Performance Polymers Inc., Northern Tier Energy, LLC, EFCH, and TCEH and is a director of the general partner of Valerus Compression Services, L.P. During the past five years, he also served on the boards of Aleris International and Texas Genco LLC prior to its sale to NRG Energy, Inc. in February 2006. Mr. MacDougall also serves as the Chairman of the Board of The Opportunity Network and is a member of the Board of the Dwight School Foundation and Islesboro Affordable Property. | |||
| Lyndon L. Olson, Jr. (3) | 63 | 2007 | Lyndon L. Olson, Jr. has served as a Director of EFH Corp. since October 2007. He was a Senior Advisor with Citigroup Inc. from 2002 to 2008, after serving as United States Ambassador to Sweden from 1998 to 2001. He previously was affiliated with Citigroup from 1990 to 1998, as President and CEO of Travelers Insurance Holdings and the Associated Madison Companies, predecessor companies. Before joining Citigroup, he had been President of the National Group Corporation and CEO of its National Group Insurance Company. Ambassador Olson also is a former Chairman and a Member of the Texas 173 State Board of Insurance, former President of the National Association of Insurance Commissioners, and a former member of the Texas House of Representatives. Ambassador Olson also serves on the board of First Acceptance Corporation, Sammons Enterprises and Texas Meter and Device Company. | |||
| Kenneth Pontarelli (2)(4) | 40 | 2007 | Kenneth Pontarelli has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He transferred to the Principal Investment Area in 1999 and was promoted to Managing Director in 2004. Mr. Pontarelli serves as a director of both public and private companies, including CCS, Inc., Cobalt International Energy, L.P., EFIH, Expro International Group Ltd. and Kinder Morgan, Inc. During the past five years, he also served on the board of CVR Energy, Inc. | |||
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Name | Age | Served As | Business Experience | |||
| William K. Reilly | 71 | 2007 | William K. Reilly has served as a Director of EFH Corp. since October 2007. He is a Senior Advisor to TPG and a founding partner of Aqua International Partners, an investment group that invests in companies that serve the water and renewable energy sectors, having previously served as the seventh Administrator of the EPA. Mr. Reilly is a director of the following public companies: E.I DuPont de Nemours and Company, ConocoPhillips and Royal Caribbean International. During the past five years, he also served on the board of Eden Springs, Ltd. of Israel. Before serving as EPA Administrator, Mr. Reilly was President of World Wildlife Fund and President of The Conservation Foundation. He previously served as Executive Director of the Rockefeller Task Force on Land Use and Urban Growth, a senior staff member of the President’s Council on Environmental Quality, Associate Director of the Urban Policy Center and the National Urban Coalition and Co-Chairman of the National Commission on Energy Policy. Mr. Reilly was appointed by the President to serve as Co-Chair of the National Commission on the Deepwater Horizon Oil Spill and Offshore Drilling. | |||
| Jonathan D. Smidt | 38 | 2007 | Jonathan D. Smidt has served as a Director of EFH Corp. since October 2007. He has been with KKR since 2000, where he is a partner and senior member of the firm’s Energy and Infrastructure team and leads KKR Natural Resources, the firm’s platform to acquire and operate oil and natural gas assets. Currently, he is a director of Laureate Education Inc. | |||
| John F. Young (2)(3) | 54 | 2008 | John F. Young has served as a Director and President and Chief Executive of EFH Corp. since January 2008. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon Corporation from March 2003 to January 2008 including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon Corporation, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation. Mr. Young is also a director of EFCH, EFIH, TCEH and Luminant. | |||
| Kneeland Youngblood (1) | 55 | 2007 | Kneeland Youngblood has served as a Director of EFH Corp. since October 2007. He is a founding partner of Pharos Capital Group, a private equity firm that focuses on providing growth and expansion capital to businesses in technology, business services and health care services. Mr. Youngblood is a director of the following public companies: Starwood Hotels and Resorts Worldwide, Inc. and Gap Inc. During the last five years, he served on the board of Burger King Holdings, Inc. Mr. Youngblood is a member of the Council on Foreign Relations. | |||
| (1) | Member of Audit Committee. |
| (2) | Member of Executive Committee. |
| (3) | Member of Governance and Public Affairs Committee |
| (4) | Member of Organization and Compensation Committee |
There is no family relationship between any of the above-named directors.
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Director Qualifications
In October 2007, David Bonderman, Donald L. Evans, Frederick M. Goltz, James R. Huffines, Scott Lebovitz, Jeffrey Liaw, Marc S. Lipschultz, Michael MacDougall, Lyndon L. Olson, Jr., Kenneth Pontarelli, William K. Reilly, Jonathan D. Smidt, and Kneeland Youngblood were elected to EFH Corp.’s board of directors (the Board). Arcilia C. Acosta, Thomas D. Ferguson and John F. Young joined the Board in 2008. Messrs. Bonderman, Ferguson, Goltz, Lebovitz, Liaw, Lipschultz, MacDougall, Pontarelli, and Smidt are collectively referred to as the “Sponsor Directors.” Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly, Young, and Youngblood are collectively referred to as the “Non-Sponsor Directors.”
Each of the Sponsor Directors was elected to the Board pursuant to the Limited Partnership Agreement of Texas Energy Future Holdings Limited Partnership, the holder of a majority of the outstanding capital stock of EFH Corp. Pursuant to this agreement, Messrs. Goltz, Lipschultz and Smidt were appointed to the Board as a consequence of their relationships with Kohlberg Kravis Roberts & Co.; Messrs. Bonderman, Liaw and MacDougall were appointed to the Board as a consequence of their relationships with TPG Capital, L.P., and Messrs. Ferguson, Lebovitz and Pontarelli were appointed to the Board as a consequence of their relationships with GS Capital Partners.
When considering whether the Board’s directors and nominees have the experience, qualifications, attributes and skills, taken as a whole, to enable the Board to satisfy its oversight responsibilities effectively in light of EFH Corp.’s business and structure, the Board focused primarily on the qualifications summarized in each of the Board member’s or nominee’s biographical information set forth on the pages above. In addition, EFH Corp. believes that each of its directors possesses high ethical standards, acts with integrity, and exercises careful judgment. Each is committed to employing his/her skills and abilities in the long-term interests of EFH Corp and its stakeholders. Finally, our directors are knowledgeable and experienced in business, governmental, and civic endeavors, further qualifying them for service as members of the Board.
The Sponsor Directors possess experience in owning and managing privately held enterprises and are familiar with corporate finance and strategic business planning activities of highly-leveraged companies such as EFH Corp. Some of the Sponsor Directors also have experience advising and overseeing the operations of large industrial, manufacturing or retail companies similar to our businesses. Finally, several of the Sponsor Directors possess substantial expertise in advising and managing companies in segments of energy industry, including, among others, power generation, oil and gas, and energy infrastructure and transportation.
As a group and individually, the Non-Sponsor Directors possess extensive experience in governmental and civic endeavors and in the business community, in each case, in the markets where our businesses operate.
Mr. Young’s employment agreement provides that he will serve as a member of the Board during the time he is employed by EFH Corp. Before joining EFH Corp. as President and Chief Executive Officer, he held various senior management positions at other companies in the energy industry over twenty years, including, most recently, his role as Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation.
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Ms. Acosta manages the operations of a large commercial construction company in Texas and has significant experience within the local Hispanic business community, having served as the chair of the Greater Dallas Hispanic Chamber of Commerce and the Texas Association of Mexican American Chambers of Commerce. Mr. Evans has demonstrated ability and achievement in both the private and public sectors, serving as U.S. Secretary of Commerce during the Bush Administration, and both before and after his government service, acting as Chairman and Chief Executive Officer of a publicly-owned energy company, Tom Brown, Inc. Mr. Huffines has demonstrated achievement in both business and academic endeavors, and, given his employment in various senior management positions in the banking industry, has sufficient experience and expertise in financial matters to qualify him to serve as EFH Corp.’s “audit committee financial expert.” Mr. Olson possesses substantial experience in both federal and state government through, among other things, his service as the former US Ambassador to Sweden and as a former member of the Texas House of Representatives, and has advised and overseen the operations of large companies, in particular his service in the insurance industry. Mr. Reilly possesses a distinguished record of public service and extensive policy-making experience as a former administrator of the EPA, lectures extensively on environmental issues facing companies operating in the energy industry and has served as Co-Chairman of the National Commission on Energy Policy. Mr. Youngblood has served on numerous boards for large public companies, has extensive experience managing and advising companies in his capacity as a partner in a private equity firm (not affiliated with the Sponsor Group), is highly knowledgeable of federal and state political matters, and has served on the board of directors of the United States Enrichment Corporation, a company that contracts with the US Department of Energy to produce enriched uranium for use in nuclear power plants.
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Executive Officers
The names and information regarding EFH Corp.’s executive officers are set forth below:
Name of Officer | Age | Positions and Offices Presently Held | Date First Elected to Present Offices | Business Experience (Preceding Five Years) | ||||
| John F. Young | 54 | President and Chief Executive Officer of EFH Corp. | January 2008 | John F. Young was elected President and Chief Executive Officer of EFH Corp. in January 2008. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon Corporation from March 2003 to January 2008, including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation. | ||||
| James A. Burke | 42 | President and Chief Executive of TXU Energy | August 2005 | James A. Burke was elected President and Chief Executive of TXU Energy in August 2005. Previously, Mr. Burke was Senior Vice President Consumer Markets of TXU Energy. | ||||
| David A. Campbell | 42 | President and Chief Executive of Luminant | June 2008 | David A. Campbell was elected President and Chief Executive of Luminant in June 2008. Mr. Campbell was Executive Vice President and Chief Financial Officer of EFH Corp. from April 2007 to June 2008 having previously served as Acting Chief Financial Officer beginning in March 2006 and as Executive Vice President for Corporate Planning, Strategy & Risk when he joined EFH Corp. in May 2004. | ||||
| Joel D. Kaplan | 41 | Executive Vice President of EFH Corp. | November 2009 | Joel D. Kaplan was elected Executive Vice President of EFH Corp. in November 2009 and oversees the company’s public affairs organization. Prior to joining EFH Corp., Mr. Kaplan served as Deputy Chief of Staff in the George W. Bush White House from 2006 to 2008 and Deputy Director of the Office of Management and Budget from 2003 to 2006. | ||||
| Paul M. Keglevic | 57 | Executive Vice President and Chief Financial Officer of EFH Corp. | July 2008 | Paul M. Keglevic was elected Executive Vice President and Chief Financial Officer of EFH Corp. in July 2008. Before joining EFH Corp., he was an audit partner at PricewaterhouseCoopers. Mr. Keglevic was PricewaterhouseCoopers’ Utility Sector Leader from 2002 to 2008 and Clients and Sector Assurance Leader from 2007 to 2008. | ||||
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Name of Officer | Age | Positions and Offices Presently Held | Date First Elected to Present Offices | Business Experience (Preceding Five Years) | ||||
| Richard J. Landy | 65 | Executive Vice President of EFH Corp. | February 2010 | Richard J. Landy was elected Executive Vice President of EFH Corp. in February 2010 and oversees human resources. Prior to joining EFH Corp., Mr. Landy was owner and consultant of Richard J. Landy, LLC from 2007 to 2009 and Senior Vice President of Exelon Corporation from 2002 to 2007. | ||||
| M. A. McFarland | 41 | Executive Vice President and Chief Commercial Officer of Luminant and Executive Vice President of EFH Corp. | July 2008 | M. A. McFarland was elected Executive Vice President and Chief Commercial Officer of Luminant and Executive Vice President of EFH Corp. in July 2008. Before joining Luminant, Mr. McFarland served as Senior Vice President of Mergers, Acquisitions and Divestitures and as a Vice President in the wholesale marketing and trading division power team at Exelon Corporation. | ||||
| Robert C. Walters (1) | 52 | Executive Vice President and General Counsel of EFH Corp. | March 2008 | Robert C. Walters was elected Executive Vice President and General Counsel of EFH Corp. in March 2008. Prior to joining EFH Corp., Mr. Walters was a Partner of Vinson & Elkins LLP and served on the firm’s management committee. Mr. Walters was co-managing partner of the Dallas office of Vinson & Elkins LLP from 1998 through 2005. | ||||
| (1) | Mr. Walters has announced his plan to resign from EFH Corp. during the first quarter 2011. |
There is no family relationship between any of the above-named executive officers.
Audit Committee Financial Expert
The Board has determined that James R. Huffines is an “Audit Committee Financial Expert” as defined in Item 407(d)(5) of SEC Regulation S-K and Mr. Huffines is independent under the New York Stock Exchange’s audit committee independence requirements for issuers of debt securities.
Code of Conduct
EFH Corp. maintains certain corporate governance documents on EFH Corp’s website atwww.energyfutureholdings.com. EFH Corp.’s Code of Conduct can be accessed by selecting “Investor Relations” on the EFH Corp. website. EFH Corp.’s Code of Conduct applies to all of its employees, officers (including the Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer) and directors. Any amendments to the Code of Conduct will be posted on EFH Corp.’s website. Printed copies of the corporate governance documents that are posted on EFH Corp.’s website are also available to any investor upon request to the Secretary of EFH Corp. at 1601 Bryan Street, Dallas, Texas 75201-3411.
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Procedures for Shareholders to Nominate Directors; Arrangement to Serve as Directors
The Amended and Restated Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC, the general partner of Texas Holdings, generally requires that the members of Texas Energy Future Capital Holdings LLC take all necessary action to ensure that the persons who serve as its managers also serve on the EFH Corp. Board. In addition, Mr. John Young’s employment agreement provides that he will be elected as a member of the Board during the time he is employed by EFH Corp.
Because of these requirements, together with Texas Holdings’ controlling ownership of EFH Corp.’s outstanding common stock, there is no policy or procedure with respect to shareholder recommendations for nominees to the EFH Corp. Board.
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| Item 11. | EXECUTIVE COMPENSATION |
Organization and Compensation Committee
The Organization and Compensation Committee (the “O&C Committee”) of EFH Corp.’s Board of Directors (the “Board”) is comprised of four non-employee directors: Arcilia C. Acosta, Donald L. Evans, Marc S. Lipschultz and Kenneth Pontarelli. The primary responsibility of the O&C Committee is to:
| • | determine and oversee the compensation program of EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities), including making recommendations to the Board with respect to the adoption, amendment or termination of compensation and benefits plans, arrangements, policies and practices; |
| • | evaluate the performance of EFH Corp.’s Chief Executive Officer (the “CEO”) and the other executive officers of EFH Corp. and its subsidiaries (other than the Oncor Ring-Fenced Entities) (collectively, the “executive officers”), including all of the executive officers named in the Summary Compensation Table (the “Named Executive Officers”), and |
| • | approve executive compensation based on those evaluations. |
Compensation Risk Assessment
EFH Corp.’s management has determined that the risks arising from EFH Corp.’s compensation policies and practices are not reasonably likely to have a material adverse effect on EFH Corp. This determination was based upon, among other things, the following: (1) the mix of cash and equity payouts at various compensation levels; (2) the performance time horizons used by our plans; (3) the use of financial performance metrics that are readily monitored and reviewed; (4) the equity investment that most of our senior and middle management employees have in EFH Corp. common stock; (5) the lack of an active trading market and other impediments to liquidity associated with EFH Corp. common stock; (6) the incorporation of both operational and financial goals and individual performance modifiers; (7) the inclusion of maximum caps and other plan-based mitigants on the amount of certain of our awards; (8) multiple levels of review and approval of awards (including approval of our O&C Committee with respect to awards to executive officers and awards to other employees that exceed monetary thresholds); and (9) our internal risk review and assessment processes.
Compensation Discussion and Analysis
Compensation of the CEO
In determining the compensation of the CEO, the O&C Committee annually follows a thorough and detailed process. At the end of each year, the O&C Committee reviews a self-assessment prepared by the CEO regarding his performance and the performance of our businesses and meets (with and without the CEO) to evaluate and discuss his performance and the performance of our businesses.
In addition to conducting an annual review of the CEO’s performance, the O&C Committee periodically uses independent compensation consultants to assess the compensation of the CEO against a variety of market reference points and competitive data, including the compensation practices of a number of companies that we consider to comprise our peer group, size-adjusted energy services industry survey data and size-adjusted general industry survey data. While the O&C Committee tries to ensure that the bulk of the CEO’s compensation is directly linked to his performance and the performance of our businesses, the O&C Committee also seeks to set his compensation in a manner that is competitive for retention purposes. The most recent assessment of the CEO’s compensation was performed in late 2010, when the O&C Committee engaged Pay Governance LLC to perform a competitive analysis of the CEO’s compensation. In December 2010, Pay Governance delivered its report to the O&C Committee, which report included market data for a peer group composed of the following companies:
| Allegheny Energy, Inc. | Ameren Corp. | American Electric Power Co. Inc | ||
| Calpine Corp. | Constellation Energy Group Inc. | Dominion Resources Inc. | ||
| Duke Energy Corp. | Edison International | Entergy Corp. | ||
| Exelon Corp. | FirstEnergy Corp. | GenOn Energy, Inc. | ||
| NextEra Energy, Inc. | NRG Energy, Inc. | PPL Corp. | ||
| Progress Energy Inc. | Public Service Enterprise Group Inc. | Southern Co. | ||
| Xcel Energy Inc. |
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The data for CEO compensation of the peer group was developed at both the 50th and 75th percentiles of market in order to provide the O&C Committee with a broad market view and multiple benchmarks. The O&C Committee targets total direct compensation at approximately the 75th percentile of the peer group.
While the O&C Committee considers market reference points and competitive data in determining the appropriate compensation of the CEO (and the other executive officers), the O&C Committee also considers qualitative and subjective factors that are more specific to EFH Corp. in making such determinations. One such factor is that EFH Corp. is a highly-leveraged, privately-owned company.
After a comprehensive review of the CEO’s performance and the performance of our businesses in 2010, and taking into consideration the Pay Governance report, the sustained decline in ERCOT wholesale power prices and forward natural gas prices, and other qualitative and subjective factors as described above, the O&C Committee approved certain changes to the long-term incentive compensation for the CEO in February 2011. The O&C Committee made these changes, which are described in more detail in Item 9B above, to provide incentives for retention and performance and to maintain a strong alignment between the CEO and our shareholders. We believe these changes are consistent with our compensation philosophy as described below.
Compensation of Other Executive Officers
In determining whether to make any adjustments to the compensation of any of our executive officers (other than the CEO), the O&C Committee seeks the input of the CEO. At the end of each year, the CEO reviews a self-assessment prepared by each of these executive officers and assesses the executive officer’s performance against business unit and individual goals and objectives. The O&C Committee and the CEO then review the CEO’s assessments and, in that context, the O&C Committee approves any adjustments to the compensation for each of these executive officers.
In addition to these annual reviews/assessments, the CEO periodically assesses the compensation of each of these executive officers. The last assessment of the compensation of the executive officers by the CEO was performed in late 2010. Following that assessment, and taking into consideration the sustained decline in ERCOT wholesale power prices and forward natural gas prices, and other qualitative and subjective factors as described above, the CEO suggested certain changes to the long-term incentive compensation for certain of our executive officers in order to provide incentives for retention and performance and to maintain alignment between our executive officers and shareholders. These changes, which are described in more detail in Item 9B above, were approved by the O&C Committee in February 2011 with respect to such executive officers, including each of Messrs. Keglevic, Campbell, Burke and McFarland. We believe these changes are consistent with our compensation philosophy as described below.
Compensation Philosophy
We have a pay-for-performance compensation philosophy, which places an emphasis on pay-at-risk. In other words, a significant portion of an executive officer’s compensation is comprised of variable, at-risk incentive compensation. Our compensation program is intended to compensate executive officers appropriately for their contribution to the attainment of our financial, operational and strategic objectives. In addition, we believe it is important to retain our executive officers and strongly align their interests with EFH Corp.’s shareholders by emphasizing long-term incentive compensation, including equity-based compensation.
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To achieve the goals of our compensation philosophy, we believe that:
| • | compensation plans should balance both long-term and short-term objectives; |
| • | the overall compensation program should emphasize variable compensation elements that have a direct link to overall corporate performance and shareholder value, and |
| • | an executive officer’s individual compensation level should be based upon an evaluation of the financial and operational performance of that executive officer’s business unit as well as the executive officer’s individual performance. |
We believe our compensation philosophy supports our businesses by:
| • | aligning performance measures with our business objectives to drive the financial and operational performance of EFH Corp. and its business units; |
| • | rewarding business unit and individual performance by providing compensation levels consistent with the level of contribution and degree of accountability; |
| • | attracting and retaining the best performers, and |
| • | strengthening the correlation between the long-term interests of our executive officers and shareholders. |
Elements of Compensation
The material elements of our executive compensation program are:
| • | a base salary; |
| • | the opportunity to earn an annual performance-based cash bonus based on the achievement of specific corporate, business unit and individual performance goals, and |
| • | long-term incentive awards, primarily in the form of (i) long-term cash incentive awards, including the modifications to these awards approved by the O&C Committee in February 2011, as described in more detail in Item 9B above, and (ii) equity awards granted pursuant to our 2007 Stock Incentive Plan for Key Employees of EFH Corp. and Affiliates (the “2007 Stock Incentive Plan”), including options to purchase shares of EFH Corp.’s common stock (the “Stock Option Awards”) and restricted stock units (the “Restricted Stock Units”). |
In addition, executive officers generally have the opportunity to participate in certain of our broad-based employee compensation plans, including our Thrift (401(k)) Plan, retirement plans and non-qualified benefit plans, and to receive certain perquisites.
Assessment of Compensation Elements
We design the majority of an executive officer’s compensation to be directly linked to corporate and business unit performance. For example, an executive officer’s annual performance-based cash bonus is primarily based on the achievement of certain corporate and business unit financial and operational targets (such as management EBITDA, cost management, generation output and customer satisfaction). In addition, each executive officer’s long-term cash incentive award (described below) is based on achievement of certain operational and financial performance metrics. We also try to ensure that our executive compensation program is competitive in order to reduce the risk of losing our executive officers.
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The following is a detailed discussion of the principal compensation elements provided to our executive officers. More detail about each of the elements can be found in the compensation tables, including the footnotes to the tables, and the narrative discussion following certain of the tables.
Base Salary
Base salary should reward executive officers for the scope and complexity of their position and the level of responsibility required. We believe that a competitive level of base salary is required to attract and retain qualified talent.
The O&C Committee annually reviews base salaries and periodically uses independent compensation consultants to ensure the base salaries are market-competitive. The O&C Committee may also review an executive officer’s base salary from time to time during a year, including if the executive officer is given a promotion or if his responsibilities are significantly modified.
We want to ensure our cash compensation is competitive and sufficient to incent executive officers to remain with us, recognizing our high performance expectations across a broad set of operational, financial, customer service and community-oriented goals and objectives and the higher risk levels associated with being a significantly-leveraged company.
In light of the significant market dislocation and uncertainty that began in late 2008 and continued into 2009, our Named Executive Officers’ base salaries were increased, effective January 1, 2010. These increases reflect, in part, that none of the Named Executive Officers received a salary increase in 2009. The following table indicates the Named Executive Officers’ base salaries for 2010.
Name | Title | Base Salary—2010 | ||||
| John F. Young | President and Chief Executive Officer of EFH Corp. | $ | 1,200,000 | |||
| Paul M. Keglevic | Executive Vice President and Chief Financial Officer of EFH Corp. | $ | 650,000 | |||
| David A. Campbell | Chief Executive Officer of Luminant | $ | 700,000 | |||
| James A. Burke | Chief Executive Officer of TXU Energy | $ | 630,000 | |||
| M.A. McFarland | Executive Vice President of EFH Corp. and Executive Vice President and Chief Commercial Officer of Luminant | $ | 600,000 | |||
Annual Performance-Based Cash Bonus - Executive Annual Incentive Plan
The Executive Annual Incentive Plan (“EAIP”) provides an annual performance-based cash bonus for the successful attainment of certain annual financial and operational performance targets that are established annually at each of the corporate and business unit levels by the O&C Committee. Under the terms of the EAIP, performance against these targets, which are generally set at challenging levels to incent high performance, drives bonus funding. Based on the level of attainment of these performance targets, an aggregate EAIP funding percentage amount for all participants is determined.
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Our financial performance targets typically include “management” EBITDA, a non-GAAP financial measure. When the O&C Committee reviews management EBITDA for purposes of determining our performance against the applicable management EBITDA target, it includes our earnings before interest, taxes, depreciation and amortization plus transaction, management and/or similar fees paid to the Sponsor Group, together with such adjustments as the O&C Committee shall determine appropriate in its discretion after good faith consultation with the CEO and the Chief Financial Officer, including adjustments consistent with those included in the comparable definitions in TCEH’s Senior Secured Facilities (to the extent considered appropriate for executive compensation purposes). Our management EBITDA targets are also expected to be adjusted for acquisitions, divestitures or major capital investment initiatives to the extent that they were not contemplated in our financial plan (the “Financial Plan”). The management EBITDA targets are intended to measure achievement of the Financial Plan and the adjustments to management EBITDA described above primarily represent elements of our performance that are either beyond the control of management or were not predictable at the time the Financial Plan was approved. Under the terms of the EAIP, the O&C Committee has broad authority to make these or any other adjustments to EBITDA that it deems appropriate in connection with its evaluation and compensation of our executive officers. Management EBITDA is an internal measure used only for performance management purposes, and EFH Corp. does not intend for management EBITDA to be an alternative to any measure of financial performance presented in accordance with GAAP. Management EBITDA is not the same as Adjusted EBITDA, which is disclosed elsewhere in this Form 10-K and defined in the glossary to this Form 10-K.
Financial and Operational Performance Targets
The following table provides a summary of the performance targets for each of the Named Executive Officers.
| Weight | ||||||||||||||||||||||||||||
Name | EFH Corp. Management EBITDA(1) | EFH Business Services Scorecard Multiplier | Luminant Scorecard Multiplier | TXU Energy Scorecard Multiplier | Luminant Energy Scorecard Multiplier | Total | Payout | |||||||||||||||||||||
John F. Young | 50 | % | 50 | % | 100 | % | 131 | % | ||||||||||||||||||||
Paul M. Keglevic | 50 | % | 50 | % | 100 | % | 130 | % | ||||||||||||||||||||
David A. Campbell | 25 | % | 75 | % | 100 | % | 132 | % | ||||||||||||||||||||
James A. Burke | 25 | % | 75 | % | 100 | % | 134 | % | ||||||||||||||||||||
M.A. McFarland | 25 | % | 25 | % | 25 | % | 25 | % | 100 | % | 143 | % | ||||||||||||||||
| (1) | Mr. Young is measured on EFH Corp. Management EBITDA, including Oncor, while the remainder of the Named Executive Officers is measured on EFH Corp. Management EBITDA, excluding Oncor. |
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The following table provides a summary of the performance targets included in the EFH Business Services Scorecard Multiplier.
EFH Business Services Scorecard Multiplier | Weight | Performance(1) | Payout | |||||||
EFH Corp. Management EBITDA (excluding Oncor) | 20.0 | % | 126% | 25% | ||||||
Luminant Scorecard Multiplier(2) | 20.0 | % | 134% | 27% | ||||||
TXU Energy Scorecard Multiplier(2) | 20.0 | % | 137% | 27% | ||||||
EFH Corp. (excluding Oncor) Total Spend | 20.0 | % | 129% | 26% | ||||||
EFH Business Services Costs | 20.0 | % | 139% | 28% | ||||||
Total | 100.0 | % | 133% | |||||||
| (1) | Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%. |
| (2) | The performance targets included in the Luminant Scorecard Multiplier and the TXU Energy Scorecard Multiplier are summarized below. |
The following table provides a summary of the performance targets included in the Luminant Scorecard Multiplier.
Luminant Scorecard Multiplier | Weight | Performance(1) | Payout | |||||||
Luminant Management EBITDA (excluding Oak Grove and Sandow 5) | 35.0 | % | 177% | 62% | ||||||
Luminant Baseload Generation - Coal (excluding Oak Grove and Sandow 5) | 16.0 | % | 99% | 16% | ||||||
Luminant Generation – Nuclear | 9.0 | % | 109% | 10% | ||||||
Luminant O&M/SG&A | 15.0 | % | 124% | 18% | ||||||
Luminant Capital Expenditures | 5.0 | % | 200% | 10% | ||||||
Luminant Fossil Fuel Costs | 10.0 | % | 111% | 11% | ||||||
Management EBITDA for Oak Grove and Sandow 5 | 10.0 | % | 67% | 7% | ||||||
Total | 100.0 | % | 134% | |||||||
| (1) | Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%. |
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The following table provides a summary of the performance targets included in the TXU Energy Scorecard Multiplier.
TXU Energy Scorecard Multiplier | Weight | Performance(1) | Payout | |||||
TXU Energy Management EBITDA | 40.0 | % | 179% | 72% | ||||
Contribution Margin | 15.0 | % | 200% | 30% | ||||
TXU Energy Total Costs | 20.0 | % | 79% | 16% | ||||
Residential Customer Count | 10.0 | % | 50% | 5% | ||||
Residential Days Meter to Cash | 5.0 | % | 100% | 5% | ||||
PUCT Complaints | 5.0 | % | 84% | 4% | ||||
Customer Satisfaction | 5.0 | % | 100% | 5% | ||||
Total | 100.0 | % | 137% | |||||
| (1) | Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%. |
The following table provides a summary of the performance targets included in the Luminant Energy Scorecard Multiplier.
Luminant Energy Scorecard Multiplier | Weight | Performance(1) | Payout(2) | |||||
Luminant Management EBITDA (excluding Oak Grove and Sandow 5) | 30.0 | % | 177% | 53% | ||||
Management EBITDA for Oak Grove and Sandow 5 | 10.0 | % | 79% | 8% | ||||
Luminant Energy SG&A | 10.0 | % | 200% | 20% | ||||
Incremental Value Created | 40.0 | % | 200% | 80% | ||||
Liquidity Utilization | 10.0 | % | 200% | 20% | ||||
Total | 100.0 | % | 181% | |||||
Adjusted Total | 178% | |||||||
| (1) | Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%. |
| (2) | Due to plan funding limitations, the actual payout related to the Luminant Energy Scorecard Multiplier has been reduced from 181% to 178%. |
Individual Performance Modifier
After approving the actual performance against the applicable targets under the plan, the O&C Committee and/or the CEO reviews the performance of each of our executive officers on an individual and comparative basis. Based on this review, which includes an analysis of both objective and subjective criteria, including the CEO’s recommendations (with respect to all executive officers other than himself), the O&C Committee approves an individual modifier for each executive officer. Under the terms of the EAIP, the individual performance modifier can range from an outstanding rating (150%) to an unacceptable rating (0%). To calculate an executive officer’s final performance-based cash bonus, the executive officer’s corporate/business unit payout percentages are multiplied by the executive officer’s target incentive level, which is computed as a percentage of annualized base salary, and then by the executive officer’s individual performance modifier.
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Actual Award
The following table provides a summary of the 2010 performance-based cash bonus for each Named Executive Officer under the EAIP.
Name | Target (% of salary) (1) | Target Award ($ Value) | Actual Award | |||||||||
John F. Young (2) | 100 | % | $ | 1,200,000 | 2,043,600 | |||||||
Paul M. Keglevic (3) | 85 | % | $ | 552,500 | 933,725 | |||||||
David A. Campbell (4) | 85 | % | $ | 595,000 | 981,750 | |||||||
James A. Burke (5) | 85 | % | $ | 535,500 | 932,841 | |||||||
M.A. McFarland (6) | 85 | % | $ | 510,000 | 948,090 | |||||||
| (1) | Effective with the 2010 award period, the O&C Committee approved an increase in the annual target award under the EAIP from 75% of base salary to 85% of base salary for Messrs. Keglevic, Campbell, Burke and McFarland. |
| (2) | Mr. Young’s incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier that increased his incentive award. In 2010, Mr. Young successfully led the company in a difficult year in which wholesale power prices continued to decline. Notwithstanding the difficulties that accompany a sustained decline in forward natural gas prices, Mr. Young created value in many parts of the company’s businesses. In particular, Mr. Young led the company’s efforts in, among other things: liquidity and liability management efforts that captured long-term debt discounts of approximately $2 billion and extended the maturity date for approximately $5 billion of our long-term debt; improving financial and operational results for our legacy baseload generation fleet, including top decile safety, generation and cost performance by our nuclear facility; providing strong contributions to the state and national debates regarding legislative and regulatory issues facing the company, including proposals on federal climate change legislation and resolution of critical regulatory matters between the EPA and the TCEQ; transitioning our generation and wholesale energy businesses to operate successfully within ERCOT’s new nodal wholesale market structure; our continued commitment to build a strong retail brand and customer-focused culture at TXU Energy; and exceeding EFH Corp.’s planned EBITDA for 2010. Given these and other significant achievements, the O&C Committee approved an individual performance modifier that increased Mr. Young’s incentive award. |
| (3) | Mr. Keglevic’s incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and EFH Business Services and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier that increased his incentive award. In 2010, Mr. Keglevic successfully managed several new financial processes at EFH Corp. and its business units, including processes for managing the varied risks of our businesses and preserving effective liquidity levels. In addition, Mr. Keglevic led the company’s liquidity and liability management efforts, including capturing long-term debt discounts of approximately $2 billion, extending the maturity date for approximately $5 billion of our long-term debt, and a resulting reduction in our interest expense of approximately $1.2 billion. Given these significant accomplishments and other achievements (including the successful resolution of a significant tax matter related to our discontinued Europe business), the O&C Committee approved an individual performance modifier that increased Mr. Keglevic’s incentive award. |
| (4) | Mr. Campbell’s incentive award is based on the successful achievement of a financial performance target for EFH Corp. and the financial and operational performance targets for Luminant and an individual performance modifier that increased his incentive award. In 2010, Mr. Campbell was successful in overseeing strong financial and operational results, primarily at Luminant’s nuclear and lignite/coal-fueled plants and in Luminant’s wholesale energy organization. Also, Mr. Campbell continued to provide significant contributions in the public affairs arena on a local, state and national level, particularly with regard to environmental issues facing Luminant. In addition, under Mr. Campbell’s leadership, Luminant had a strong year for safety in its nuclear and mining operations, while implementing improved safety processes and metrics for its gas and lignite/coal-fueled plants and mines. Given these significant accomplishments and other achievements (including his focus on developing a collaborative, team-oriented culture across the organization), the O&C Committee approved an individual performance modifier that increased Mr. Campbell’s incentive award. |
| (5) | Mr. Burke’s incentive award is based on the successful achievement of a financial performance target for EFH Corp. and the financial and operational performance targets for TXU Energy and an individual performance modifier that increased his incentive award. In 2010, Mr. Burke continued to build on TXU Energy’s brand and reputation with its customers and public stakeholders, while driving continuous improvement in customer service, billing, marketing and retention activities. Given these significant accomplishments and other achievements (including his continued commitment to build a strong retail and customer-focused culture at TXU Energy), the O&C Committee approved an individual performance modifier that increased Mr. Burke’s incentive award. |
| (6) | Mr. McFarland’s incentive award is based on the successful achievement of the financial performance targets for EFH Corp., the financial and operational performance targets for Luminant and Luminant Energy and an individual performance modifier that increased his incentive award. In 2010, Mr. McFarland successfully transitioned our generation and wholesale energy businesses to operate successfully within ERCOT’s new nodal wholesale market structure, successfully managed Luminant’s fuel strategy, and developed several new processes for managing Luminant’s long-term hedging strategy with minimal impacts to liquidity. Given these significant accomplishments and other achievements (including his strategic contributions with regard to a number of development opportunities), the O&C Committee approved an individual performance modifier that increased Mr. McFarland’s incentive award. |
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Long-Term Incentive Awards
Long-Term Cash Incentive
In October 2009 (and in February 2010, with respect to Mr. Young), each of our Named Executive Officers was granted a long-term cash incentive award (the “LTI”) that entitles such Named Executive Officer to receive on September 30, 2012, to the extent such Named Executive Officer remains employed by EFH Corp. on such date (with customary exceptions in limited circumstances, including death, disability, and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 75% (100% with respect to Mr. Young) of the aggregate EAIP award received by such executive officer for fiscal years 2009, 2010 and 2011. These awards provide significant retentive value because an award is not paid to an executive officer unless the executive officer remains employed with us until September 30, 2012 (subject to the customary exceptions described above). In addition, these awards provide additional incentive to our executive officers to achieve top operational and financial performance because the award is based on a percentage of the executive officers’ annual performance-based cash bonuses.
Long-Term Equity Incentives
We believe it is important to strongly align the interests of our executive officers and shareholders through equity-based compensation. In December 2007, our Board approved and adopted our 2007 Stock Incentive Plan pursuant to which we granted Stock Option Awards to our executive officers. The purpose of the 2007 Stock Incentive Plan is to:
| • | promote our long-term financial interests and growth by attracting and retaining management and other personnel with the training, experience and ability to make a substantial contribution to our success; |
| • | motivate management and other personnel by means of growth-related incentives to achieve long-range goals, and |
| • | strengthen the correlation between the long-term interests of our shareholders and the interests of our executive officers through opportunities for stock (or stock-based) ownership in EFH Corp. |
Please refer to the outstanding Equity Awards at Fiscal Year-End—2010 table, including the footnotes thereto, for a more detailed description of the outstanding Stock Option Awards held by each of the Named Executive Officers. In the future, we may make additional discretionary grants of stock options or other equity-based compensation to reward high performance or achievement.
As described in greater detail in Item 9B above, the O&C Committee recently approved an exchange program pursuant to which our executive officers, including the Named Executive Officers, may exchange any and all of their outstanding Stock Option Awards for restricted stock units that cliff-vest on September 30, 2014.
Other Elements of Compensation
General
Our executive officers generally have the opportunity to participate in certain of our broad-based employee compensation plans, including our Thrift (401(k)) Plan, retirement plans and non-qualified benefit plans. Please refer to the footnotes to the Summary Compensation table for a more detailed description of our Thrift Plan, the narrative that follows the Pension Benefits table for a more detailed description of our Retirement Plan and Supplemental Retirement Plan and the footnotes to the Nonqualified Deferred Compensation table for a more detailed description of our Salary Deferral Program. However, beginning in 2010, our Named Executive Officers are no longer eligible to participate in the Salary Deferral Program.
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Perquisites
We provide our executives with certain perquisites on a limited basis. Those perquisites that exist are generally intended to enhance our executive officers’ ability to conduct company business. These benefits include, financial planning, preventive health maintenance, and reimbursement for certain club memberships and certain spousal travel expenses. Expenditures for the perquisites described below are disclosed by individual in footnotes to the Summary Compensation Table. The following is a summary of perquisites offered to our Named Executive Officers that are not available to all employees:
Executive Financial Planning:We pay for our executive officers to receive financial planning services. This service is intended to support them in managing their financial affairs, which we consider especially important given the high level of time commitment and performance expectation required of our executive officers. Furthermore, we believe that such service helps ensure greater accuracy and compliance with individual tax regulations by our executive officers.
Health Services:We pay for our executive officers to receive annual physical health exams. Also, in 2010, we purchased an annual membership for Messrs. Young and Keglevic to participate in a comprehensive health plan that provides anytime personal and private physician access and health care. The health of our executive officers is important given the vital leadership role they play in directing and operating the company. Our executive officers are important assets of EFH Corp., and these benefits are designed to help ensure their health and long-term ability to serve our shareholders.
Club Memberships:We reimburse certain of our executives for the cost of golf and social club memberships, provided that the club membership provides for a business-use opportunity, such as client networking and entertainment. The club membership reimbursements are provided to assist the executives in cultivating business relationships.
Spouse Travel Expenses:From time to time, we pay for an executive officer’s spouse to travel with the executive officer when taking a business trip.
Contingent Payments
We have entered into employment agreements with Messrs. Young, Keglevic, Campbell, Burke and McFarland. Each of the employment agreements provides that certain payments and benefits will be paid upon the expiration or termination of the agreement under various circumstances, including termination without cause, resignation for good reason and termination of employment within a fixed period of time following a change in control. We believe these provisions are important in order to attract and retain the caliber of executive officers that our business requires and provide incentive for our executive officers to fully consider potential changes that are in our and our shareholders’ best interest, even if such changes would result in the executive officers’ termination of employment. For a description of the applicable provisions in the employment agreements of our Named Executive Officers see “Potential Payments upon Termination or Change in Control.”
Other
After a comprehensive review of the CEO’s performance and the performance of our businesses in 2009, the O&C Committee approved several changes to Mr. Young’s compensation arrangement in February 2010, each of which was described in greater detail in last year’s annual report on Form 10-K. In connection with these changes, Mr. Young’s employment arrangement was amended to provide him a 10-year term life insurance policy in an insured amount equal to $10,000,000 and a supplemental retirement plan that vests on December 31, 2014 (with customary exceptions for death, disability and leaving for “good reason” or termination “without cause”) with a value of $3,000,000.
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Accounting and Tax Considerations
Accounting Considerations
Under FASB ASC Topic 718, the total amount of compensation expense to be recorded for stock-based awards (e.g., Stock Option Awards granted under the 2007 Stock Incentive Plan) is based on the fair value of the award on the grant date. This fair value is then recorded as expense over the vesting period, with an offsetting increase in paid-in capital. The amount of compensation expense is not subsequently adjusted for changes in our share price, for the actual number of shares distributed, or for any other factors except for true-ups related to estimated forfeitures compared to actual forfeitures.
As previously disclosed, in connection with a grant of new stock options in February 2010, Mr. Young surrendered unvested performance-related stock options that were granted to him when he joined EFH Corp. The shares surrendered by Mr. Young in February 2010 are considered modifications to the original awards and are treated as an exchange of the original award for a new award. The compensation expense related to the new award represents the incremental costs of the new award over the surrendered award and is based on the new grant date fair value and is recognized over its new vesting period.
Income Tax Considerations
Section 162(m) of the Code limits the tax deductibility by a publicly held company of compensation in excess of $1 million paid to the CEO or any other of its three most highly compensated executive officers other than the principal financial officer. Because EFH Corp. is a privately-held company, Section 162(m) will not limit the tax deductibility of any executive compensation for 2010.
The O&C Committee administers our compensation programs with the good faith intention of complying with Section 409A of the Code.
Organization and Compensation Committee Report
The O&C Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth in this Form 10-K. Based on this review and discussions, the committee recommended to the Board that the Compensation Discussion and Analysis be included in this Form 10-K.
Organization and Compensation Committee
Donald L. Evans, Chair
Arcilia C. Acosta
Marc S. Lipschultz
Kenneth Pontarelli
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Summary Compensation Table—2010
The following table provides information for the fiscal years ended December 31, 2010, 2009 and 2008 regarding the aggregate compensation paid to our Named Executive Officers.
Name and Principal Position | Year | Salary ($) | Bonus ($) | Stock Awards ($) | Option Awards ($)(6) | Non-Equity Incentive Plan Compensation ($)(7) | Change in Pension Value and Non-qualified Deferred Compensation Earnings ($)(8) | All Other Compensation ($)(9) | Total ($) | |||||||||||||||||||||||||
John F. Young (1) | 2010 2009 2008 |
| 1,200,000 1,000,000 912,500 |
|
| — — — |
|
| — — 3,000,000 |
|
| 3,405,000 — 13,635,000 |
|
| 2,043,600 1,469,000 1,418,000 |
|
| 2,761 — — |
|
| 210,826 105,291 462,258 |
|
| 6,862,187 2,574,291 19,427,758 |
| |||||||||
Paul M. Keglevic(2) | 2010 2009 2008 |
| 650,000 600,000 293,182 |
|
| 50,000 150,000 250,000 |
|
| — — 1,125,000 |
|
| — 1,325,000 6,442,500 |
|
| 933,725 664,200 613,800 |
|
| 3,185 — — |
|
| 39,416 73,320 88,508 |
|
| 1,676,326 2,812,520 8,812,990 |
| |||||||||
David A. Campbell(3) | 2010 2009 2008 | | 700,000 600,000 | |
| — — 5,092,250 |
|
| — — 2,500,000 |
|
| — 2,120,000 7,272,000 |
|
| 981,750 642,600 625,950 |
|
| 76,485 68,861 22,779 |
|
| 17,911 15,020 3,395,878 |
|
| 1,776,146 3,446,481 19,454,357 |
| |||||||||
James A. Burke(4) | 2010 2009 2008 |
| 630,000 600,000 600,000 |
|
| — — — |
|
| — — — |
|
| — 933,100 4,454,100 |
|
| 932,841 856,800 473,918 |
|
| 76,713 55,931 25,501 |
|
| 17,305 23,885 639,136 |
|
| 1,656,859 2,469,716 6,192,655 |
| |||||||||
M.A. McFarland (5) | 2010 2009 2008 |
| 600,000 500,000 236,744 |
|
| — — 150,000 |
|
| — — 500,000 |
|
| — 1,060,000 5,114,000 |
|
| 948,090 687,750 529,032 |
|
| — — — |
|
| 17,418 7,424 87,725 |
|
| 1,565,508 2,255,174 6,617,501 |
| |||||||||
| (1) | Mr. Young commenced employment with EFH Corp. in January 2008. The amounts for 2010 reported as “All Other Compensation” for Mr. Young represent (i) the costs of providing certain perquisites, including $3,299 for an executive physical, $11,169 for an annual membership in a comprehensive personal physician care program, $140,922 for the cost of his country club membership, including the one-time initiation fee, $10,120 for financial planning, $17,185 for insurance premiums in respect of a 10-year term life insurance policy, $1,121 for personal use of a car service and $12,310 of taxable reimbursements partially related to his spouse’s travel and (ii) $14,700 for our matching contributions to the EFH Thrift Plan. |
| (2) | Mr. Keglevic commenced employment with EFH Corp. in July 2008. Mr. Keglevic’s employment agreement provides that we pay him a signing bonus equal to $550,000 as follows: (i) $250,000 payable in July 2008; (ii) $150,000 payable in July 2009 and (iii) $50,000 payable in July 2010, 2011 and 2012. The amount for 2010 reported as “Bonus” for Mr. Keglevic represents the 2010 portion of his signing bonus. The amounts for 2010 reported as “All Other Compensation” for Mr. Keglevic represent (i) the costs of providing certain perquisites, including $11,026 for an annual membership in a comprehensive personal physician care program, and $18,853 for the cost of his country club membership, including a pro-rated portion of his initiation fee and (ii) $9,537 for our matching contributions to the EFH Thrift Plan. |
| (3) | The amount reported as “All Other Compensation” in 2010 for Mr. Campbell represents (i) the costs of providing certain perquisites, including $10,120 for financial planning and $2,891 for an executive physical and (ii) $4,900 for our matching contributions to the EFH Thrift Plan. |
| (4) | The amounts for 2010 reported as “All Other Compensation” for Mr. Burke represent (i) the costs of providing certain perquisites, including $8,875 for financial planning, and (ii) $8,430 for our matching contributions to the EFH Thrift Plan. |
| (5) | Mr. McFarland commenced employment with EFH Corp. in July 2008. The amounts for 2010 reported as “All Other Compensation” for Mr. McFarland represent (i) the costs of providing certain perquisites, including $2,718 for an executive physical and (ii) $14,700 for our matching contributions to the EFH Thrift Plan. |
| (6) | The amounts reported as “Option Awards” represent the grant date fair value of Stock Option Awards granted in the fiscal year computed for the stock options awarded under the 2007 Stock Incentive Plan in accordance with FASB ASC Topic 718 and do not take into account estimated forfeitures. Mr. Young’s 2010 options were granted with an exercise price of $3.50 per share. Please refer to the table below entitled “Grants of Plan-Based Awards – 2010” for more information. |
| (7) | The amounts in 2010 reported as “Non-Equity Incentive Plan Compensation” were earned by the executive officers in 2010 under the EAIP and are expected to be paid in March 2011. |
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| (8) | The amounts in 2010 reported under “Change in Pension Value and Nonqualified Deferred Compensation Earnings” include the aggregate increase in actuarial value of EFH Corp.’s Retirement Plan and Supplemental Retirement Plan. For a more detailed description of EFH Corp.’s retirement plans, including the transfers of certain assets and liabilities from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan, please refer to the narrative that follows the table titled “Pension Benefits”. There are no above market earnings for nonqualified deferred compensation that is deferred under the Salary Deferral Program. |
| (9) | For purposes of preparing this column, all perquisites are valued on the basis of the actual cost to the company. As described above, “All Other Compensation” includes amounts associated with our matching contributions to the EFH Thrift Plan. Our Thrift Plan allows participating employees to contribute a portion of their regular salary or wages to the plan. Under the EFH Thrift Plan, EFH Corp. matches a portion of an employee’s contributions. This matching contribution is 100% of each Named Executive Officer’s contribution up to 6% of the named Executive Officer’s salary up to the IRS annual compensation limit. All matching contributions are invested in Thrift Plan investments as directed by the participant. |
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Grants of Plan-Based Awards – 2010
The following table sets forth information regarding grants of compensatory awards to our Named Executive Officers during the fiscal year ended December 31, 2010.
Name | Grant Date | Date of Board Action | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1) | All Other Option Awards: # of Securities Underlying Options (#)(2) | Exercise or Base Price of Option Awards ($/sh)(3) | Grant Date Fair Value of Stock and Option Awards(4) | ||||||||||||||||||||||||||
| Threshold ($) | Target ($) | Max. ($) | ||||||||||||||||||||||||||||||
John F. Young | 02/18/10 | 02/18/10 | 600,000 | 1,200,000 | 2,400,000 | 3,000,000 | 3.50 | 3,405,000 | ||||||||||||||||||||||||
Paul M. Keglevic | 02/18/10 | 276,250 | 552,500 | 1,105,000 | ||||||||||||||||||||||||||||
David A. Campbell | 02/18/10 | 297,500 | 595,000 | 1,190,000 | ||||||||||||||||||||||||||||
James A. Burke | 02/18/10 | 267,750 | 535,500 | 1,071,000 | ||||||||||||||||||||||||||||
M.A. McFarland | 02/18/10 | 255,000 | 510,000 | 1,020,000 | ||||||||||||||||||||||||||||
| (1) | The amounts disclosed under the heading “Estimated Possible Payouts under Non-Equity Incentive Plan Awards” reflect the threshold, target and maximum amounts available under the EAIP for each executive officer and each executive officer’s employment agreement. The actual awards for the 2010 plan year are expected to be paid in March 2011 and are reported in the Summary Compensation Table under the heading “Non-Equity Incentive Plan Compensation” and described above under the section entitled “Annual Performance Bonus - EAIP”. |
| (2) | Represents grants of new Time Vested Options and Cliff Vested Options under the 2007 Stock Incentive Plan, as described above under “Long-Term Incentive Awards.” |
| (3) | There is no established public market for our common stock. Our board of directors values our common stock on a semi-annual basis (on June 30th and December 31st of each year). The valuation is primarily done to set the exercise or base price of awards granted under the 2007 Stock Incentive Plan. In determining the valuation of our common stock, our Board, with the assistance of third party valuation experts, utilizes several valuation techniques, including discounted cash flow and comparable company analysis. |
| (4) | The amounts reported under “Grant Date Fair Value of Stock and Option Awards” represent the grant date fair value of stock options related to the 2010 Awards in accordance with FASB ASC Topic 718. |
For a discussion of certain material terms of the employment agreements with the Named Executive Officers, please see “Assessment of Compensation Elements” and “Potential Payments upon Termination or Change in Control.”
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Outstanding Equity Awards at Fiscal Year-End– 2010
| Option Awards (1) | Stock Awards | |||||||||||||||||||||||||||||||||
| Equity Incentive Plan Awards: # of Securities Underlying Unexercised Unearned Options (5) | Option Exercise Price | Option Expiration Date | # of Shares or Units of Stock That Have Not Vested (6) | Market Value of Shares or Units of Stock That Have Not Vested (7) | Equity Incentive Plan Awards: # of Unearned Shares, Units or Other Rights That Have Not Vested | Equity Incentive Plan Awards: Market Payout Value of Unearned Shares, Units or Rights That Have Not Vested | ||||||||||||||||||||||||||||
| # of Securities Underlying Unexercised Options | ||||||||||||||||||||||||||||||||||
Name | Exercisable | Unexercisable | ||||||||||||||||||||||||||||||||
John F. Young |
| 3,375,000 300,000 |
|
| 1,500,000 1,200,000 1,500,000 | (2) (3) (4) | 1,125,000 |
| 5.00 3.50 3.50 |
| 02/01/2018 02/18/2020 02/18/2020 | |||||||||||||||||||||||
Paul M. Keglevic |
| 1,125,000 100,000 |
|
| 500,000 400,000 500,000 | (2) (3) (4) | 375,000 |
| 5.00 3.50 3.50 |
| 12/22/2018 12/17/2019 12/17/2019 | 225,000 | 281,250 | |||||||||||||||||||||
David A. Campbell |
| 1,800,000 160,000 |
|
| 800,000 640,000 800,000 | (2) (3) (4) | 600,000 |
| 5.00 3.50 3.50 |
| 05/20/2018 12/17/2019 12/17/2019 | |||||||||||||||||||||||
James A. Burke |
| 1,102,500 40,000 |
|
| 490,000 160,000 490,000 | (2) (3) (4) | 367,500 |
| 5.00 3.50 3.50 |
| 05/20/2018 12/17/2019 12/17/2019 | |||||||||||||||||||||||
M.A. McFarland |
| 900,000 80,000 |
|
| 400,000 320,000 400,000 | (2) (3) (4) | 300,000 |
| 5.00 3.50 3.50 |
| 12/22/2018 12/17/2019 12/17/2019 | |||||||||||||||||||||||
| (1) | In 2008, Messrs. Young, Keglevic, Campbell, Burke and McFarland were granted 7,500,000, 2,500,000, 4,000,000, 2,450,000 and 2,000,000 Stock Option Awards, respectively, half of which were “Time Vested Options” and half of which were “Performance Vested Options”. The exercise price of the Stock Option Awards granted in 2008 (the fair market value on the grant date) is $5.00 per share. In late 2009 (February 2010, with respect to Mr. Young), the O&C Committee granted Messrs. Young, Keglevic, Campbell, Burke and McFarland 1,500,000, 500,000, 800,000, 200,000 and 400,000 new Time Vested Options, respectively, and 1,500,000, 500,000, 800,000, 490,000 and 400,000 “Cliff Vested Options,” respectively. In connection with these new Stock Option Award grants, each Named Executive Officer surrendered to EFH Corp. a portion of the Performance Vested Options that were granted to him in 2008. The exercise price of the Stock Option Awards granted in 2009 (2010, with respect to Mr. Young) is $3.50 per share. As described in greater detail in Item 9B above, the O&C Committee recently approved an exchange program pursuant to which our executive officers, including the Named Executive Officers, may exchange any and all of their outstanding Stock Option Awards for restricted stock units that cliff-vest on September 30, 2014. |
| (2) | The Time Vested Options vest in 20% increments on each of the first five anniversaries of September 30, 2007 and September 30, 2009, respectively. Accordingly, the Time Vested Options granted in 2008 are scheduled to become exercisable ratably in September 2010, 2011 and 2012 provided the Named Executive Officer has remained continuously employed by EFH Corp. through the applicable vesting date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”). |
| (3) | The Time Vested Options granted in 2009 (2010, with respect to Mr. Young) are scheduled to become exercisable ratably in September 2010, 2011, 2012, 2013 and 2014 provided the Named Executive Officer has remained continuously employed by EFH Corp. through the applicable vesting date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”). |
| (4) | The Cliff Vested Options are scheduled to become exercisable in September 2014 provided the Named Executive Officer has remained continuously employed by EFH Corp. through that date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”). |
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| (5) | The Performance Vested Options vest in 20% increments on each of the first five anniversaries of December 31, 2007, subject to our achievement of the annual management EBITDA target for the given fiscal year (or certain cumulative performance targets) as detailed in the stock option agreements. In deciding whether to vest the Performance Vested Options, the O&C Committee considers EFH Corp.’s quantitative performance against certain management EBITDA targets. The method of calculating management EBITDA for purposes of vesting the Performance Vested Options is the same as the method for calculating management EBITDA for purposes of the EAIP, as described above. The O&C Committee also has broad discretion to consider other qualitative and quantitative criteria that it deems appropriate in connection with its decision to vest the Performance Vested Options. |
| (6) | This column reflects restricted stock units described above under “Long-Term Incentive Awards-Equity Investment.” Pursuant to his employment arrangement, Mr. Keglevic is entitled to receive 225,000 shares of EFH Corp.’s common stock if he is employed by EFH Corp. on September 30, 2012, or if his employment terminates for any reason prior to September 30, 2012, other than for “cause” or without “good reason.” If Mr. Keglevic receives the 225,000 shares, he has the right to sell the shares to EFH Corp. for $3,140,000, at any time during the period beginning on September 30, 2012 and ending on the sixtieth business day following his termination of employment (or, in the event Mr. Keglevic receives the shares upon his termination of employment, at any time during the period ending on the sixtieth business day following his termination of employment). |
| (7) | There is no established public market for our common stock. Our board of directors values our common stock on a semi-annual basis (on June 30th and December 31st of each year). The valuation is primarily done to set the exercise or base price of awards granted under the 2007 Stock Incentive Plan. In determining the valuation of our common stock, our Board, with the assistance of third party valuation experts, utilizes several valuation techniques, including discounted cash flow and comparable company analysis. The amount reported above under the heading “Market Value of Shares or Units of Stock That Have Not Vested” reflects the fair market value (as determined by our Board) of our common stock as of December 31, 2010. |
Options Exercised and Stock Vested – 2010
The table sets forth information regarding the vesting of equity awards held by the Named Executive Officers during 2010:
| Option Awards | Stock Awards | |||||||||||||||
Name | Number of Shares Acquired or Exercised | Value Realized on Exercise($) | Number of Shares Acquired on Vesting | Value Realized on Vesting ($) | ||||||||||||
John F. Young (1) | 0 | 0 | 600,000 | 1,950,000 | ||||||||||||
Paul M. Keglevic | 0 | 0 | 0 | 0 | ||||||||||||
David A. Campbell | 0 | 0 | 0 | 0 | ||||||||||||
James A. Burke | 0 | 0 | 0 | 0 | ||||||||||||
M.A. McFarland (1) (2) | 0 | 0 | 100,000 | 200,000 | ||||||||||||
| (1) | As described in greater detail above, our board of directors values our common stock on a semi-annual basis (on June30th and December 31st of each year). The valuation is conducted, in part, to set the price of shares granted under the 2007 Stock Incentive Plan. At the time that Mr. Young’s shares vested, our board of directors valued our common stock at $3.25 per share. At the time that Mr. McFarland’s shares vested, our board of directors valued our common stock at $2.00 per share. |
| (2) | Mr. McFarland’s deferred shares were distributed to him in October 2010, but they remain subject to a substantial risk of forfeiture. |
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Pension Benefits – 2010
The table set forth below illustrates present value on December 31, 2010 of each Named Executive Officer’s Retirement Plan benefit and benefits payable under the Supplemental Retirement Plan, based on their years of service and remuneration through December 31, 2010:
Name | Plan Name | Number of Years Credited Service (#)(1) | PV of Accumulated Benefit ($) | |||||||
John F. Young | Retirement Plan Supplemental Retirement Plan |
| — — |
|
| 36,074 0 |
| |||
Paul M. Keglevic | Retirement Plan Supplemental Retirement Plan |
| — — |
|
| 47,594 0 |
| |||
David A. Campbell | Retirement Plan Supplemental Retirement Plan |
| 5.5833 8.5000 |
|
| 135,418 85,817 |
| |||
James A. Burke | Retirement Plan Supplemental Retirement Plan |
| 5.1667 5.1667 |
|
| 123,253 82,253 |
| |||
M.A. McFarland | Retirement Plan Supplemental Retirement Plan |
| — — |
|
| 0 0 |
| |||
| (1) | Because they were hired after October 1, 2007, Messrs. Young, Keglevic and McFarland are not eligible to receive monthly contribution credits under the cash balance component of our Retirement Plan. However, as described further in the narrative that follows, Messrs. Young and Keglevic participate in the cash balance component of the Retirement Plan solely with respect to amounts that were transferred from the Salary Deferral Program in 2009. |
EFH Corp. and its participating subsidiaries maintain the Retirement Plan, which is intended to be qualified under applicable provisions of the Code and covered by ERISA. The Retirement Plan contains both a traditional defined benefit component and a cash balance component. Only employees hired before January 1, 2002 may participate in the traditional defined benefit component. Because none of our Named Executive Officers were hired before January 1, 2002, no Named Executive Officer participates in the traditional defined benefit component. Employees hired after January 1, 2002 and before October 1, 2007 are eligible to participate in the cash balance component and receive monthly contribution credits based on age and years of accredited service. In addition, effective December 31, 2009, certain assets and liabilities under the Salary Deferral Program and the Supplemental Retirement Plan were transferred to the cash balance component of the Retirement Plan. Because they were hired in 2004, Messrs. Campbell and Burke have participated and may continue to participate in the cash balance component of the Retirement Plan, and because they were hired after October 2007, Messrs. Young and Keglevic participate in the cash balance component of the Retirement Plan solely with respect to amounts that were transferred from the Salary Deferral Program.
Under the cash balance component of the Retirement Plan, hypothetical accounts are established for participants and credited with monthly contribution credits equal to a percentage of the participant’s compensation (3.5%, 4.5%, 5.5% or 6.5% depending on the participant’s combined age and years of accredited service), contribution credits equal to the amounts transferred from the Salary Deferral Program and/or the Supplemental Retirement Plan in 2009 and interest credits on all of such amounts based on the average yield of the 30-year Treasury bond for the 12 months ending November 30 of the prior year.
The Supplemental Retirement Plan provides for the payment of retirement benefits, which would otherwise be limited by the Code or the definition of earnings under the Retirement Plan. Under the Supplemental Retirement Plan, retirement benefits under the cash balance component are calculated in accordance with the same formula used under the Retirement Plan. Participation in EFH Corp.’s Supplemental Retirement Plan has been limited to employees of all of its businesses other than Oncor, who were employed by EFH Corp. (or its participating subsidiaries) on or before October 1, 2007. Because they were hired in 2004, Messrs. Campbell and Burke participate in the Supplemental Retirement Plan, and because they were hired after October 2007, Messrs. Young, Keglevic and McFarland are not eligible to participate in the Supplemental Retirement Plan.
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Benefits accrued under the Supplemental Retirement Plan after December 31, 2004, are subject to Section 409A of the Code. Accordingly, certain provisions of the Supplemental Retirement Plan have been modified in order to comply with the requirements of Section 409A and related guidance.
The present value of the accumulated benefit for the Retirement Plan (the cash balance component) was calculated as the value of their cash balance account projected to age 65 at an assumed growth rate of 4.75% and then discounted back to December 31, 2010 at 5.5%. No mortality or turnover assumptions were applied.
Nonqualified Deferred Compensation – 2010(1)
The following table sets forth information regarding plans that provide for the deferral of the Named Executive Officers’ compensation on a basis that is not tax-qualified for the fiscal year ended December 31, 2010:
Name | Executive Contributions in Last FY ($) | Registrant Contributions in Last FY ($) | Aggregate Earnings in Last FY ($) | Aggregate Withdrawals/ Distributions ($) | Aggregate Balance at Last FYE ($)(2) | |||||||||||||||
John F. Young | 0 | 0 | 27,686 | 309,402 | ||||||||||||||||
Paul M. Keglevic | 0 | 0 | (46 | ) | 87,656 | |||||||||||||||
David A. Campbell (3) | 0 | 0 | 42,965 | 863,856 | ||||||||||||||||
James A. Burke (3) | 0 | 0 | 44,135 | 839,898 | ||||||||||||||||
M.A. McFarland | 0 | 0 | 0 | 0 | ||||||||||||||||
| (1) | The amounts reported in the Nonqualified Deferred Compensation table include deferrals and the company match under the Salary Deferral Program. Under EFH Corp.’s Salary Deferral Program each employee of EFH Corp. and its participating subsidiaries who is in a designated job level and whose annual salary is equal to or greater than an amount established under the Salary Deferral Program ($110,840 for the program year beginning January 1, 2010) may elect to defer up to 50% of annual base salary, and/or up to 85% of the annual incentive award, for a maturity period of seven years, for a maturity period ending with the retirement of such employee, or for a combination thereof. EFH Corp. provided no matching contributions for 2010. Deferrals are credited with earnings or losses based on the performance of investment alternatives under the Salary Deferral Program selected by each participant. At the end of the applicable maturity period, the trustee for the Salary Deferral Program distributes the deferred compensation, any vested matching awards and the applicable earnings in cash as a lump sum or in annual installments at the participant’s election made at the time of deferral. EFH Corp. is financing the retirement option portion of the Salary Deferral Program through the purchase of corporate-owned life insurance on the lives of participants. The proceeds from such insurance are expected to allow EFH Corp. to fully recover the cost of the retirement option. Beginning in 2010, certain executive officers, including the Named Executive Officers, are not eligible to participate in the Salary Deferral Program. |
| (2) | A portion of the amounts reported as “Aggregate Balance at Last FYE” are also included in the Summary Compensation Table as follows: for Mr. Young, $80,000 and $66,667 of executive contributions are included as “Salary” for 2009 and 2008, respectively, and $80,000 and $66,667 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively; for Mr. Keglevic, $48,000 and $20,000 of executive contributions are included as “Salary” for, 2009 and 2008, respectively, and $48,000 and $20,000 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively; for Mr. Burke, $48,000 and $27,417 of executive contributions are included as “Salary” for 2009 and 2008, respectively, and $48,000 and $27,417 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively. |
| (3) | The amounts reported as “Aggregate Balance at Last FYE” for Messrs. Campbell and Burke include the fair market value of deferred shares (500,000 with respect to Mr. Campbell and 450,000 with respect to Mr. Burke) that each of them is entitled to receive on the earlier to occur of their termination of employment or a change in the effective control of EFH Corp. |
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Potential Payments upon Termination or Change in Control
The tables and narrative below provide information for payments to each of the Named Executive Officers (or, as applicable, enhancements to payments or benefits) in the event of his termination, including if such termination is voluntary, for cause, as a result of death, as a result of disability, without cause or for good reason or without cause or for good reason in connection with a change in control.
The information in the tables below is presented in accordance with SEC rules, assuming termination of employment as of December 31, 2010.
Employment Arrangements with Contingent Payments
As of December 31, 2010, each of Messrs. Young, Keglevic, Campbell, Burke and McFarland had employment agreements with change in control and severance provisions as described in the following tables. In addition, in 2010, the O&C Committee approved certain changes to the compensation arrangements for Messrs. Young and Keglevic, which changes were effective on or before December 31, 2010 but not yet documented in such Named Executive Officers’ employment agreements. Certain of these changes affected the potential payments of Messrs. Young and Keglevic and are reflected in the following tables.
With respect to each Named Executive Officer’s employment agreement, a change in control is generally defined as (i) a transaction that results in a sale of substantially all of our assets to another person and such person having more seats on our Board than the Sponsor Group, (ii) a transaction that results in a person not in the Sponsor Group owning more than 50% of our common stock and such person having more seats on our Board than the Sponsor Group or (iii) a transaction that results in the Sponsor Group owning less than 20% of our common stock and the Sponsor Group not being able to appoint a majority of the directors to our Board.
Each Named Executive Officer’s employment agreement includes customary non-compete and non-solicitation provisions that generally restrict the Named Executive Officer’s ability to compete with us or solicit our customers or employees for his own personal benefit during the term of the employment agreement and 24 months (with respect to Mr. Young) or 18 months (with respect to Messrs. Keglevic, Campbell, Burke and McFarland) after the employment agreement expires or is terminated.
Each of our Named Executive Officers has been granted a long-term cash incentive award (the “LTI”) that entitles such Named Executive Officer to receive on September 30, 2012, to the extent such Named Executive Officer remains employed by EFH Corp. on such date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 75% (100% with respect to Mr. Young) of the aggregate EAIP award received by such executive officer for fiscal years 2009, 2010 and 2011.
As of December 31, 2010, each of Messrs. Young, Keglevic, Campbell, Burke and McFarland had stock option agreements. Under the stock option agreement for each Named Executive Officer, in the event of such Named Executive Officer’s termination without cause or resignation for good reason (or in certain circumstances when the Named Executive Officer’s employment term is not extended) following a change in control of EFH Corp., such Named Executive Officer’s Time Vested Options would become immediately exercisable as to 100% of the shares of EFH Corp. common stock subject to such options immediately prior to the change in control. As of December 31, 2010, the fair market value of the shares of EFH Corp. common stock underlying each Named Executive Officer’s Time Vested Options (as determined from time to time by our Board) was less than the exercise price of such options.
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1. Mr. Young
Potential Payments to Mr. Young upon Termination as of December 31, 2010 (per employment agreement, restricted stock agreement and stock option agreement, each in effect as of December 31, 2010, and revisions to such employment agreement that were adopted by the O&C Committee and effective as of December 31, 2010)
Benefit | Voluntary | For Cause | Death | Disability | Without Cause Or For Good Reason | Without Cause Or For Good Reason In Connection With Change in Control | ||||||||||||||||||
Cash Severance | N/A | N/A | $ | 6,869,000 | $ | 9,869,000 | ||||||||||||||||||
EAIP | N/A | N/A | $ | 1,200,000 | $ | 1,200,000 | ||||||||||||||||||
Annuity | N/A | N/A | $ | 3,000,000 | $ | 3,000,000 | $ | 3,000,000 | $ | 3,000,000 | ||||||||||||||
LTI Cash Retention Award | N/A | N/A | $ | 2,669,000 | $ | 2,669,000 | ||||||||||||||||||
Deferred Compensation | ||||||||||||||||||||||||
- Salary Deferral Program | N/A | N/A | $ | 175,346 | $ | 175,346 | $ | 175,346 | ||||||||||||||||
Health & Welfare | ||||||||||||||||||||||||
- Medical/COBRA | N/A | N/A | $ | 33,323 | $ | 33,323 | ||||||||||||||||||
- Dental/COBRA | N/A | N/A | $ | 2,990 | $ | 2,990 | ||||||||||||||||||
Totals | N/A | N/A | $ | 7,044,346 | $ | 7,044,346 | $ | 9,905,313 | $ | 13,080,659 | ||||||||||||||
Mr. Young has entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
| 1. | In the event of Mr. Young’s death or disability: |
| a. | a prorated annual incentive bonus for the year of termination; |
| b. | value of supplemental retirement plan (the “Annuity”) for Mr. Young that vests on December 31, 2014 |
| c. | the pro-rata retention award earned prior to termination date, and |
| d. | payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled. |
2. In the event of Mr. Young’s termination without cause or resignation for good reason:
| a. | a lump sum payment equal to two and one-half times the sum of (i) his annualized base salary and (ii) a prorated annual incentive bonus for the year of termination; |
| b. | value of supplemental retirement plan (the “Annuity”) for Mr. Young that vests on December 31, 2014 |
| c. | the pro-rata retention award earned prior to termination date; |
| d. | payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled, and |
| e. | certain continuing health care and company benefits. |
3. In the event of Mr. Young’s termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:
| a. | a lump sum payment equal to two and one-half times the sum of (i) his annualized base salary and (ii) his annual bonus target; |
| b. | value of supplemental retirement plan (the “Annuity”) for Mr. Young that vests on December 31, 2014 |
| c. | the pro-rata retention award earned prior to termination date; |
| d. | a prorated annual incentive bonus for the year of termination; |
| e. | payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled; |
| f. | certain continuing health care and company benefits, and |
| g. | a tax gross-up payment to offset any excise tax which may result from the change in control payments. |
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2. Mr. Keglevic
Potential Payments to Mr. Keglevic upon Termination as of December 31, 2010 (per employment agreement, deferred share agreement and stock option agreement, each in effect as of December 31, 2010, and revisions to such employment agreement that were adopted by the O&C Committee and effective as of December 31, 2010)
Benefit | Voluntary | For Cause | Death | Disability | Without Cause Or For Good Reason | Without Cause Or For Good Reason In Connection With Change in Control | ||||||||||||||||||
Cash Severance | N/A | N/A | $ | 2,765,025 | $ | 3,317,525 | ||||||||||||||||||
EAIP | N/A | N/A | $ | 552,500 | $ | 552,500 | ||||||||||||||||||
Payment of EFH Corp. Common Stock in respect of Restricted Stock Units (1) | N/A | N/A | $ | 3,140,000 | $ | 3,140,000 | $ | 3,140,000 | $ | 3,140,000 | ||||||||||||||
Acceleration of Stock Option Awards | N/A | N/A | ||||||||||||||||||||||
LTI Cash Retention Award | N/A | N/A | $ | 912,525 | $ | 912,525 | ||||||||||||||||||
Deferred Compensation | ||||||||||||||||||||||||
- Salary Deferral Program | N/A | N/A | $ | 68,071 | $ | 68,071 | $ | 68,071 | ||||||||||||||||
Health & Welfare | ||||||||||||||||||||||||
- Dental/COBRA | N/A | N/A | $ | 1,590 | $ | 1,590 | ||||||||||||||||||
Totals | N/A | N/A | $ | 4,673,096 | $ | 4,673,096 | $ | 5,906,615 | $ | 6,527,186 | ||||||||||||||
| (1) | Pursuant to his amended employment arrangement, Mr. Keglevic is entitled to receive 225,000 shares of EFH Corp.’s common stock if he is employed by EFH Corp. on September 30, 2012, or if his employment terminates for any reason prior to September 30, 2012, other than for “cause” or without “good reason.” If Mr. Keglevic receives the 225,000 shares, he has the right to sell the shares to EFH Corp. for $3,140,000, at any time during the period beginning on September 30, 2012 and ending on the sixtieth business day following his termination of employment (or, in the event Mr. Keglevic receives the shares upon his termination of employment, at any time during the period ending on the sixtieth business day following his termination of employment). |
Mr. Keglevic entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
| 1. | In the event of Mr. Keglevic’s death or disability: |
| a. | a prorated annual incentive bonus for the year of termination; |
| b. | the pro-rata retention award earned prior to termination, and |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled. |
2. In the event of Mr. Keglevic’s termination without cause or resignation for good reason:
| a. | a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination; |
| b. | the pro-rata retention award earned prior to termination; |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled, and |
| d. | certain continuing health care and company benefits. |
3. In the event of Mr. Keglevic’s termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:
| a. | a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target; |
| b. | the pro-rata retention award earned prior to termination; |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled; |
| d. | certain continuing health care and company benefits, and |
| e. | a tax gross-up payment to offset any excise tax which may result from the change in control payments. |
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3. Mr. Campbell
Potential Payments to Mr. Campbell upon Termination as of December 31, 2010 (per employment agreement, deferred share agreement and stock option agreement, each in effect as of December 31, 2010)
Benefit | Voluntary | For Cause | Death | Disability | Without Cause Or For Good Reason | Without Cause Or For Good Reason In Connection With Change in Control | ||||||||||||||||||
Cash Severance | $ | 2,923,200 | $ | 3,518,200 | ||||||||||||||||||||
EAIP | $ | 595,000 | $ | 595,000 | ||||||||||||||||||||
Distribution of Deferred Shares (1) | $ | 625,000 | $ | 625,000 | $ | 625,000 | $ | 625,000 | $ | 625,000 | $ | 625,000 | ||||||||||||
Acceleration of Stock Option Awards | ||||||||||||||||||||||||
LTI Cash Retention Award | $ | 928,200 | $ | 928,200 | ||||||||||||||||||||
Retirement Benefits | ||||||||||||||||||||||||
- Supplemental Retirement Plan | $ | 99,096 | $ | 99,096 | $ | 99,096 | $ | 99,096 | $ | 99,096 | $ | 99,096 | ||||||||||||
Deferred Compensation | ||||||||||||||||||||||||
- Salary Deferral Program (2) | ||||||||||||||||||||||||
Health & Welfare | ||||||||||||||||||||||||
- Medical/COBRA | $ | 25,873 | $ | 25,873 | ||||||||||||||||||||
- Dental/COBRA | $ | 2,392 | $ | 2,392 | ||||||||||||||||||||
Totals | $ | 725,096 | $ | 725,096 | $ | 2,247,296 | $ | 2,247,296 | $ | 3,675,561 | $ | 4,270,561 | ||||||||||||
| (1) | The amount reported under the heading “Distribution of Deferred Shares” represents the fair market value of 500,000 shares of EFH Corp. common stock that Mr. Campbell is entitled to receive, pursuant to the terms of his deferred share agreement, on the earlier to occur of his termination of employment for any reason or a change in the effective control of EFH Corp. |
| (2) | Mr. Campbell is fully vested in the company matching portion of the Salary Deferral Plan. |
Mr. Campbell entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
| 1. | In the event of Mr. Campbell’s death or disability: |
| a. | a prorated annual incentive bonus for the year of termination, |
| b. | the pro-rata retention award earned prior to the date of termination, and |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled. |
2. In the event of Mr. Campbell’s termination without cause or resignation for good reason:
| a. | a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the pro-rata retention award earned prior to the date of termination; |
| b. | payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled, and |
| c. | certain continuing health care and company benefits. |
3. In the event of Mr. Campbell’s termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:
| a. | a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target; |
| b. | the pro-rata retention award; |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled; |
| d. | certain continuing health care and company benefits, and |
| e. | a tax gross-up payment to offset any excise tax which may result from the change in control payments. |
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4. Mr. Burke
Potential Payments to Mr. Burke upon Termination as of December 31, 2010 (per employment agreement and stock option agreement, each in effect as of December 31, 2010)
Benefit | Voluntary | For Cause | Death | Disability | Without Cause Or For Good Reason | Without Cause Or For Good Reason In Connection With Change in Control | ||||||||||||||||||
Cash Severance | $ | 2,839,725 | $ | 3,375,225 | ||||||||||||||||||||
EAIP | $ | 535,500 | $ | 535,500 | ||||||||||||||||||||
Acceleration of Stock Option Awards Vesting of Options Distribution of Deferred Shares (1) | $ | 562,500 | $ | 562,500 | $ | 562,500 | $ | 562,500 | $ | 562,500 | $ | 562,500 | ||||||||||||
LTI Cash Retention Award | $ | 1,044,225 | $ | 1,044,225 | ||||||||||||||||||||
Retirement Benefits | ||||||||||||||||||||||||
- Supplemental Retirement Plan | $ | 93,464 | $ | 93,464 | $ | 93,464 | $ | 93,464 | $ | 93,464 | $ | 93,464 | ||||||||||||
Deferred Compensation | ||||||||||||||||||||||||
- Salary Deferral Program | $ | 74,077 | $ | 74,077 | $ | 74,077 | ||||||||||||||||||
Health & Welfare | ||||||||||||||||||||||||
- Medical/COBRA | $ | 25,873 | $ | 25,873 | ||||||||||||||||||||
- Dental/COBRA | $ | 2,392 | $ | 2,392 | ||||||||||||||||||||
Totals | $ | 655,964 | $ | 655,964 | $ | 2,309,766 | $ | 2,309,766 | $ | 3,523,954 | $ | 4,133,531 | ||||||||||||
| (1) | The amount reported under the heading “Distribution of Deferred Shares” represents the fair market value of 450,000 shares of EFH Corp. common stock that Mr. Burke is entitled to receive, pursuant to the terms of his deferred share agreement, on the earlier to occur of his termination of employment for any reason or a change in the effective control of EFH Corp. |
Mr. Burke entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
| 1. | In the event of Mr. Burke’s death or disability: |
| a. | a prorated annual incentive bonus for the year of termination; |
| b. | the pro-rata retention award earned prior to termination, and |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled. |
2. In the event of Mr. Burke’s termination without cause or resignation for good reason:
| a. | a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination; |
| b. | the pro-rata retention award earned prior to termination; |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled, and |
| d. | certain continuing health care and company benefits. |
3. In the event of Mr. Burke’s termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:
| a. | a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target; |
| b. | the pro-rata retention award earned prior to termination; |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled; |
| d. | certain continuing health care and company benefits and |
| e. | a tax gross-up payment to offset any excise tax which may result from the change in control payments. |
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5. Mr. McFarland
Potential Payments to Mr. McFarland upon Termination as of December 31, 2010 (per employment agreement and stock option agreement, each in effect as of December 31, 2010)
Benefit | Voluntary | For Cause | Death | Disability | Without Cause Or For Good Reason | Without Cause Or For Good Reason In Connection With Change in Control | ||||||||||||||||||
Cash Severance | N/A | N/A | $ | 2,608,313 | $ | 3,118,313 | ||||||||||||||||||
EAIP | N/A | N/A | $ | 510,000 | $ | 510,000 | ||||||||||||||||||
Acceleration of Stock Option Awards | N/A | N/A | ||||||||||||||||||||||
LTI Cash Retention Award | N/A | N/A | $ | 898,313 | $ | 898,313 | ||||||||||||||||||
Lump Sum Payment | N/A | N/A | ||||||||||||||||||||||
Deferred Compensation | ||||||||||||||||||||||||
- Salary Deferral Program | N/A | N/A | ||||||||||||||||||||||
Health & Welfare | ||||||||||||||||||||||||
- Medical/COBRA | N/A | N/A | $ | 25,873 | $ | 25,873 | ||||||||||||||||||
- Dental/COBRA | N/A | N/A | $ | 2,392 | $ | 2,392 | ||||||||||||||||||
Totals | N/A | N/A | $ | 1,408,313 | $ | 1,408,313 | $ | 2,636,578 | $ | 3,146,578 | ||||||||||||||
Mr. McFarland entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
| 1. | In the event of Mr. McFarland’s death or disability: |
| a. | a prorated annual incentive bonus for the year of termination; |
| b. | the pro-rata retention award earned prior to termination, and |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. McFarland may be entitled. |
2. In the event of Mr. McFarland’s termination without cause or resignation for good reason:
| a. | a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination; |
| b. | the pro-rata retention award earned prior to termination; |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. McFarland may be entitled, and |
| d. | certain continuing health care and company benefits. |
3. In the event of Mr. McFarland’s termination without cause or resignation for good reason within 24 months following a change in control of EFH Corp.:
| a. | a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target; |
| b. | the pro-rata retention award earned prior to termination; |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. McFarland may be entitled; |
| d. | certain continuing health care and company benefits, and |
| e. | a tax gross-up payment to offset any excise tax which may result from the change in control payments. |
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Excise Tax Gross-Ups
Pursuant to their employment agreements, if any of our Named Executive Officers would be subject to the imposition of the excise tax imposed by Section 4999 of the Code, related to the executive’s employment, but the imposition of such tax could be avoided by approval of our shareholders as described in Section 280G(b)(5)(B) of the Code, then such executive may cause EFH Corp. to seek such approval, in which case EFH Corp. will use its reasonable best efforts to cause such approval to be obtained and such executive will cooperate and execute such waivers as may be necessary so that such approval avoids imposition of any excise tax under Section 4999. If such executive fails to cause EFH Corp. to seek such approval or fails to cooperate and execute the waivers necessary in the approval process, such executive shall not be entitled to any gross-up payment for any resulting tax under Section 4999.
Compensation Committee Interlocks and Insider Participation
There are no relationships among our executive officers, members of the O&C Committee or entities whose executives served on the O&C Committee that required disclosure under applicable SEC rules and regulations. For a description of related person transactions involving members of the O&C Committee, see Item 13, entitled “Related Person Transactions.”
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Director Compensation
The table below sets forth information regarding the aggregate compensation paid to the members of the Board during the year ended December 31, 2010. Directors who are officers of EFH Corp. or members of the Sponsor Group (or their respective affiliates) do not receive any fees for service as a director. EFH Corp. reimburses directors for certain reasonable expenses incurred in connection with their services as directors.
Name | Fees Earned or Paid in Cash ($) | Stock Awards ($) | All Other Compensation ($) | Total ($) | ||||||||||||
Arcilia C. Acosta (1) | 150,000 | 100,000 | — | 250,000 | ||||||||||||
David Bonderman | — | — | — | — | ||||||||||||
Donald L. Evans (2) | 2,000,000 | — | — | 2,000,000 | ||||||||||||
Thomas D. Ferguson | — | — | — | — | ||||||||||||
Frederick M. Goltz | — | — | — | — | ||||||||||||
James R. Huffines (1) | 150,000 | 100,000 | — | 250,000 | ||||||||||||
Scott Lebovitz | — | — | — | — | ||||||||||||
Jeffrey Liaw | — | — | — | — | ||||||||||||
Marc S. Lipschultz | — | — | — | — | ||||||||||||
Michael MacDougall | — | — | — | — | ||||||||||||
Lyndon L. Olson, Jr. (1) | 150,000 | 100,000 | — | 250,000 | ||||||||||||
Kenneth Pontarelli | — | — | — | — | ||||||||||||
William K. Reilly (1) | 150,000 | 100,000 | — | 250,000 | ||||||||||||
Jonathan D. Smidt | — | — | — | — | ||||||||||||
John F. Young | — | — | — | — | ||||||||||||
Kneeland Youngblood (1) | 150,000 | 100,000 | — | 250,000 | ||||||||||||
| (1) | Ms. Acosta and Messrs. Huffines, Olson, Reilly and Youngblood receive $150,000 annually and an annual equity award (paid in shares of EFH Corp. common stock) valued at $100,000 (the grant date fair value) for their service as a director. |
| (2) | In February 2010, EFH Corp. entered into a new consulting agreement with Mr. Evans effective retroactively to October 10, 2009, pursuant to which Mr. Evans receives an annual fee of $2,000,000. The term of the new consulting agreement expires in October 2012. |
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| Item 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The following table presents information concerning stock-based compensation plans as of December 31, 2010. (See Note 21 to Financial Statements.)
| (a) Number of securities to be issued upon exercise of outstanding options, warrants and rights | (b) Weighted-average exercise price of outstanding options, warrants and rights | (c) Number of securities remaining available for future issuance under equity compensation plans, excluding securities reflected in column (a) | ||||||||||
Equity compensation plans approved by security holders | — | $ | — | — | ||||||||
Equity compensation plans not approved by security holders | 65,333,309 | $ | 4.29 | 6,666,691 | ||||||||
Total | 65,333,309 | $ | 4.29 | 6,666,691 | ||||||||
| Note: | Includes 48.4 million stock options with a weighted average exercise price of $4.50. | |
| Includes 8.4 million vested and unvested restricted shares, deferred shares and stock granted to directors as part of their compensation plan. | ||
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Beneficial Ownership of Common Stock of Energy Future Holdings Corp.
The following table lists the number of shares of common stock of EFH Corp. beneficially owned by each director and certain executive officers of EFH Corp. and the holders of more than 5% of EFH Corp.’s common stock as of February 1, 2011.
Name | Number of Shares Beneficially Owned | Percent of Class | ||||||
Texas Energy Future Holdings Limited Partnership (1) | 1,657,600,000 | 97.81 | % | |||||
Arcilia C. Acosta (2) | 100,770 | * | ||||||
David Bonderman (3) | 1,657,600,000 | 97.81 | % | |||||
Donald L. Evans (4) | 1,000,000 | * | ||||||
Thomas D. Ferguson (5) | 1,657,600,000 | 97.81 | % | |||||
Frederick M. Goltz (6) | 1,657,600,000 | 97.81 | % | |||||
James R. Huffines | 390,770 | * | ||||||
Scott Lebovitz (5) | 1,657,600,000 | 97.81 | % | |||||
Jeffrey Liaw (3) | 1,657,600,000 | 97.81 | % | |||||
Marc S. Lipschultz (6) | 1,657,600,000 | 97.81 | % | |||||
Michael MacDougall (3) | 1,657,600,000 | 97.81 | % | |||||
Lyndon L. Olson, Jr. | 250,770 | * | ||||||
Kenneth Pontarelli (5) | 1,657,600,000 | 97.81 | % | |||||
William K. Reilly | 230,770 | * | ||||||
Jonathan D. Smidt (6) | 1,657,600,000 | 97.81 | % | |||||
John F. Young (7) | 5,062,009 | * | ||||||
Kneeland Youngblood | 170,770 | * | ||||||
James A. Burke (8) | 1,715,000 | * | ||||||
David A. Campbell (9) | 2,660,000 | * | ||||||
Paul M. Keglevic (10) | 1,575,000 | |||||||
M. A. McFarland (11) | 1,143,550 | * | ||||||
All directors and current executive officers as a group (24 persons) (12) | 1,674,219,409 | 98.79 | % | |||||
| * | Less than 1%. |
| (1) | Texas Holdings beneficially owns 1,657,600,000 shares of EFH Corp. The sole general partner of Texas Holdings is Texas Energy Future Capital Holdings LLC (Texas Capital), which, pursuant to the Amended and Restated Limited Partnership Agreement of Texas Holdings, has the right to vote all of the EFH Corp. shares owned by Texas Holdings. The address of both Texas Holdings and Texas Capital is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102. |
| (2) | 70,000 shares held in a family limited partnership, ACA Family LP. |
| (3) | Includes the 1,657,600,000 shares owned by Texas Holdings, over which TPG Partners V, L.P., TPG Partners IV, L.P., TPG FOF V-A, L.P. and TPG FOF V-B, L.P. (TPG Entities) may be deemed, as a result of their ownership of 27.01% of Texas Capital’s outstanding units and certain provisions of Texas Capital’s Amended and Restated Limited Liability Company Agreement (TC LLC Agreement), to have shared voting or dispositive power. The ultimate general partners of the TPG Entities are TPG Advisors IV, Inc. and TPG Advisors V, Inc. David Bonderman and James Coulter are the sole shareholders and directors of TPG Advisors IV Inc. and TPG Advisors V Inc., and therefore, Messrs. Bonderman and Coulter, TPG Advisors IV Inc. and TPG Advisors V Inc. may each be deemed to beneficially own the shares held by the TPG Entities. Messrs. Bonderman, Liaw and MacDougall are managers of Texas Capital. By virtue of their position in relation to Texas Capital and the TPG Entities, Messrs. Bonderman, Liaw and MacDougall may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Liaw and MacDougall disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102. |
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| (4) | Includes 600,000 shares issuable upon exercise of vested options. |
| (5) | Includes the 1,657,600,000 shares owned by Texas Holdings, over which GS Capital Partners VI Fund, L.P., GSCP VI Offshore TXU Holdings, L.P., GSCP VI Germany TXU Holdings, L.P., GS Capital Partners VI Parallel, L.P., GS Global Infrastructure Partners I, L.P., GS Infrastructure Offshore TXU Holdings, L.P. (GSIP International Fund), GS Institutional Infrastructure Partners I, L.P., Goldman Sachs TXU Investors L.P. and Goldman Sachs TXU Investors Offshore Holdings, L.P. (collectively, Goldman Entities) may be deemed, as a result of their ownership of 27.02% of Texas Capital’s outstanding units and certain provision of the TC LLC Agreement, to have shared voting or dispositive power. Affiliates of The Goldman Sachs Group, Inc. (Goldman Sachs) are the general partner, managing general partner or investment manager of each of the Goldman Entities, and each of the Goldman Entities shares voting and investment power with certain of their respective affiliates. Each of Goldman Sachs and the Goldman Entities disclaims beneficial ownership of such shares of common stock except to the extent of its pecuniary interest therein. Messrs. Ferguson, Lebovitz and Pontarelli are managers of Texas Capital and executives with affiliates of Goldman Sachs. By virtue of their position in relation to Texas Capital and the Goldman Entities, Messrs. Ferguson, Lebovitz and Pontarelli may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Ferguson, Lebovitz and Pontarelli disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is c/o Goldman, Sachs & Co., 85 Broad Street, New York, New York 10004. |
| (6) | Includes the 1,657,600,000 shares owned by Texas Holdings, over which KKR 2006 Fund L.P., KKR PEI Investments, L.P., KKR Partners III, L.P., KKR North American Co-Invest Fund I L.P. and TEF TFO Co-Invest, LP (KKR Entities) may be deemed, as a result of their ownership of 37.05% of Texas Capital’s outstanding units and certain provision of the TC LLC Agreement, to have shared voting or dispositive power. The KKR Entities disclaim beneficial ownership of any shares of our common stock in which they do not have a pecuniary interest. Messrs. Goltz, Lipschultz and Smidt are managers of Texas Capital and executives of Kohlberg Kravis Roberts & Co. L.P. By virtue of their position in relation to Texas Capital and the KKR Entities, Messrs. Goltz, Lipschultz and Smidt may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Goltz, Lipschultz and Smidt disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, Suite 4200, New York, New York 10019. |
| (7) | Includes 4,050,000 shares issuable upon exercise of vested options. |
| (8) | Includes 450,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 1,265,00 shares issuable upon exercise of vested options. |
| (9) | Includes 500,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 2,160,000 shares issuable upon exercise of vested options. |
| (10) | Includes 225,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 1,350,000 shares issuable upon exercise of vested options. |
| (11) | Includes 1,080,000 shares issuable upon exercise of vested options. |
| (12) | The Organization and Compensation Committee of EFH Corp.’s Board of Directors recently approved an exchange program pursuant to which EFH Corp.’s executive officers may exchange any and all of their outstanding options for restricted stock units that cliff-vest on September 30, 2014. |
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| Item 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Policies and Procedures Relating to Related Party Transactions
The Board has adopted a policy regarding related person transactions. Under this policy, a related person transaction shall be consummated or shall continue only if:
| 1. | the Audit Committee of the Board approves or ratifies such transaction in accordance with the policy and determines that the transaction is on terms comparable to those that could be obtained in arm’s length dealings with an unrelated third party; |
| 2. | the transaction is approved by the disinterested members of the Board or the Executive Committee; or |
| 3. | the transaction involves compensation approved by the Organization and Compensation Committee of the Board. |
For purposes of this policy, the term “related person” includes EFH Corp.’s directors, executive officers, 5% shareholders and their immediate family members. “Immediate family members” means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law or any person (other than a tenant or employee) sharing the household of a director, executive officer or 5% shareholder.
A “related person transaction” is a transaction between EFH Corp. or its subsidiaries and a related person, other than the types of transactions described below, which are deemed to be pre-approved by the Audit Committee of the Board:
| 1. | any compensation paid to a director if the compensation is required to be reported under Item 402 of Regulation S-K of the Securities Act; |
| 2. | any transaction with another company at which a related person’s only relationship is as an employee (other than an executive officer), director or beneficial owner of less than 10% of that company’s ownership interests; |
| 3. | any charitable contribution, grant or endowment by EFH Corp. to a charitable organization, foundation or university at which a related person’s only relationship is as an employee (other than an executive officer) or director; |
| 4. | transactions where the related person’s interest arises solely from the ownership of EFH Corp.’s equity securities and all holders of that class of equity securities received the same benefit on a pro rata basis; |
| 5. | transactions involving a related party where the rates or charges involved are determined by competitive bids; |
| 6. | any transaction with a related party involving the rendering of services as a common or contract carrier, or public utility, as rates or charges fixed in conformity with law or governmental authority; |
| 7. | any transaction with a related party involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture, or similar service; |
| 8. | transactions available to all employees or customers generally (unless required to be disclosed under Item 404 of Regulation S-K of the Securities Act, if applicable); |
| 9. | transactions involving less than $100,000 when aggregated with all similar transactions; |
| 10. | transactions between EFH Corp. and its subsidiaries or between subsidiaries of EFH Corp.; |
| 11. | transactions not required to be disclosed under Item 404 of Regulation S-K under the Securities Act of 1933, and |
| 12. | open market purchases of the EFH Corp. or its subsidiaries’ debt or equity securities and interest payments on such debt. |
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The Board has determined that it is appropriate for the Audit Committee of the Board to review and approve or ratify related person transactions. Accordingly, at least annually, management reviews related person transactions to be entered into by EFH Corp. or its subsidiaries, if any. After review, the Audit Committee of the Board approves/ratifies or disapproves such transactions. Management updates the Audit Committee of the Board as to any material changes to such related person transactions. In unusual circumstances, EFH Corp. or its subsidiaries may enter into related person transactions in advance of receiving approval, provided that such related person transactions are reviewed and ratified as soon as reasonably practicable by the Audit Committee of the Board. If the Audit Committee of the Board determines not to ratify such transactions, EFH Corp. makes all reasonable efforts to cancel or otherwise terminate the affected transactions.
The related person transactions described below under “Related Person Transactions – Business Affiliations,” were ratified by the Audit Committee of the Board pursuant to the policy described above. All other related person transactions were approved prior to the Board’s adoption of this policy, but were approved by either the Board or its Executive Committee. Transactions described below under “Related Person Transactions – Transactions with Sponsor Affiliates” are not related person transactions under the EFH Corp. policy because they are not with a director, executive officer, 5% shareholder or any of their immediate family members, but are described in the interest of greater disclosure.
Related Person Transactions
Limited Partnership Agreement of Texas Energy Future Holdings Limited Partnership; Limited Liability Company Agreement of Texas Energy Future Capital Holdings LLC
The Sponsor Group and certain investors who agreed to co-invest with the Sponsor Group or through a vehicle jointly controlled by the Sponsor Group to provide equity financing for the Merger (Co-Investors) entered into (i) a limited partnership agreement (LP Agreement) in respect of EFH Corp.’s parent company, Texas Holdings and (ii) the LLC Agreement in respect of Texas Holdings’ sole general partner, Texas Capital. The LP Agreement provides that Texas Capital has the right to vote or execute consents with respect to any shares of EFH Corp.’s common stock owned by Texas Holdings. The LLC Agreement and LP Agreement contain agreements among the parties with respect to the election of EFH Corp.’s directors, restrictions on the issuance or transfer of interests in EFH Corp., including tag-along rights and drag-along rights, and other corporate governance provisions (including the right to approve various corporate actions).
The LLC Agreement provides that Texas Capital and its members will take all action required to ensure that the managers of Texas Capital are also members of EFH Corp.’s Board. Pursuant to the LLC Agreement each of (i) KKR 2006 Fund L.P. and affiliated investment funds, (ii) TPG Partners V, L.P. and affiliated investment funds and (iii) certain funds affiliated with Goldman Sachs, has the right to designate three managers of Texas Capital. These rights are subject to maintenance of certain investment levels in Texas Holdings.
Registration Rights Agreement
The Sponsor Group and the Co-Investors entered into a registration rights agreement with EFH Corp. upon completion of the Merger. Pursuant to this agreement, in certain circumstances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.’s common stock owned directly or indirectly by them under the Securities Act. In certain circumstances, the Sponsor Group and the Co-Investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.’s common stock under the Securities Act that it may undertake. In 2008 and 2009, Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and Messrs. Young, Campbell, Walters, Burke, Keglevic, McFarland, Kaplan and Landy, each of whom are executive officers of EFH Corp., became parties to this agreement.
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Management Services Agreement
In October 2007, in connection with the Merger, the Sponsor Group and Lehman Brothers Inc. entered into a management agreement with EFH Corp. (Management Agreement), pursuant to which affiliates of the Sponsor Group provide management, consulting, financial and other advisory services to EFH Corp. Pursuant to the Management Agreement, affiliates of the Sponsor Group are entitled to receive an aggregate annual management fee of $35 million, which amount increases 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of EFH Corp. or in connection with an initial public offering of EFH Corp. or if the parties thereto mutually agree to terminate the Management Agreement. Pursuant to the Management Agreement, affiliates of the Sponsor Group and Lehman Brothers Inc. were paid transaction fees an aggregate $300 million for certain services provided in connection with the Merger and related transactions. In addition, the Management Agreement provides that the Sponsor Group will be entitled to receive a fee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition, merger combination and change of control transactions, as well as a termination fee based on the net present value of future payment obligations under the Management Agreement in the event of an initial public offering or under certain other circumstances. Under terms of the Management Agreement, EFH Corp. paid approximately $37 million, inclusive of expenses, to the Sponsor Group during 2010.
Indemnification Agreement
Concurrently with entering into the Management Agreement, the Sponsor Group, Texas Holdings and EFH Corp. entered into an indemnification agreement (Indemnification Agreement), pursuant to which EFH Corp. and Texas Holdings agree to indemnify the Sponsor Group and their affiliates against any claims relating to (i) certain securities and financing transactions relating to the Merger, (ii) the performance of transaction services pursuant to the Management Agreement, (iii) actions or failures to act by EFH Corp., Texas Holdings, Texas Capital or their subsidiaries or affiliates (collectively, Company Group), (iv) service as an officer or director of, or at the request of, any member of the Company Group, and (v) any breach or alleged breach of fiduciary duty as a director or officer of any member of the Company Group.
Sale Participation Agreement
Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and Messrs. Young, Campbell, Walters, Burke, Keglevic, McFarland, Kaplan and Landry, each of whom are executive officers, entered into sale participation agreements with EFH Corp. Pursuant to the terms of these agreements, among other things, shares of EFH Corp.’s common stock held by these individuals are subject to tag-along and drag-along rights in the event of a sale by the Sponsor Group of shares of EFH Corp.’s common stock held by the Sponsor Group.
Certain Charter Provisions
EFH Corp.’s restated certificate of formation contains provisions limiting our directors’ obligations in respect of corporate opportunities.
Management Stockholders’ Agreement
Subject to a management stockholders’ agreement, certain members of management, including EFH Corp.’s directors, executive officers, along with other members of management, elected to invest in EFH Corp. by contributing cash or common stock, or a combination of both, to EFH Corp. prior to or following the Merger and receiving common stock in EFH Corp. in exchange therefore. The net aggregate amount of this investment as of December 31, 2010 is approximately $40.5 million. The management stockholders’ agreement creates certain rights and restrictions on these shares of common stock, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.
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Director Stockholders’ Agreement
Certain members of our Board have entered into a stockholders’ agreement with EFH Corp. These stockholders’ agreements create certain rights and restrictions on the equity, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.
Business Affiliations
Mr. Olson, a member of our board, has an ownership interest in Texas Meter and Device Company (TMD), a company that conducts tests on Oncor’s high voltage personal protective equipment. Mr. Olson and his brother collectively directly own approximately 24% of TMD. This entity is majority owned by its chief executive officer who is not related to Mr. Olson. In 2010, Oncor paid TMD approximately $1 million. The business relationship with TMD commenced several years prior to Mr. Olson joining the Board.
Transactions with Sponsor Affiliates
TCEH has entered into the TCEH Senior Secured Facilities, and Oncor has entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners. These transactions were approved by the Board.
Goldman participated in the issuance of new senior secured notes by EFH Corp. in January 2010 and senior secured second lien notes by TCEH in October 2010 and was paid fees in the amounts of approximately $3 million and $1 million, respectively, as compensation for its services. Also, Goldman acted as dealer manager and solicitation agent in connection with the debt exchange offers completed in August 2010 by EFIH and EFIH Finance and was paid a fee in the amount of $7 million for its services (see Note 22 to Financial Statements for additional information).
Affiliates of GS Capital Partners have from time to time engaged in commercial and investment banking and financial advisory transactions with EFH Corp. in the normal course of business. Affiliates of Goldman are party to certain commodity and interest rate hedging transactions with EFH Corp. in the normal course of business.
From time to time affiliates of the Sponsor Group may acquire debt or debt securities issued by EFH Corp. or its subsidiaries in open market transactions or through loan syndications.
Members of the Sponsor Group and/or their respective affiliates have from time to time entered into, and may continue to enter into, arrangements with us to use our products and services in the ordinary course of their business, which often result in revenues to us in excess of $120,000 annually. In addition, we have entered into, and may continue to enter into, arrangements with members of the Sponsor Group and/or their respective affiliates to use their products and services in the ordinary course of their business, which often result in revenues to members of the Sponsor Group or their respective affiliates in excess of $120,000 annually.
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Director Independence
Though not formally considered by the Board because EFH Corp.’s common stock is not currently registered under the Exchange Act of 1934 with the SEC or traded on any national securities exchange, based upon the listing standards for issuers of equity securities on the New York Stock Exchange (NYSE), the national securities exchange upon which EFH Corp.’s common stock was traded prior to the Merger, only Ms. Acosta and Mr. Youngblood would be considered independent. Because of their relationships with the Sponsor Group or with EFH Corp. directly, none of the other directors would be considered independent under the NYSE listing standards for issuers of equity securities. See “Certain Relationships and Related Party Transactions” and Item 11, “Executive Compensation – Director Compensation.” Accordingly, we believe that Ms. Acosta is the only member of the Organization and Compensation Committee who would meet the NYSE’s independence requirements for issuers of equity securities. We believe that none of the members of EFH Corp.’s Governance and Public Affairs Committee would meet the NYSE’s independence requirements for issuers of equity securities. Under the NYSE’s audit committee independence requirement for issuers of debt securities, Messrs. Huffines and Youngblood and Ms. Acosta, who constitute the Audit Committee, are considered independent.
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| Item 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
Deloitte & Touche LLP has been the independent auditor for EFH Corp. and for its Predecessor (TXU Corp.) since its organization in 1996.
The Audit Committee of the EFH Corp. Board of Directors has adopted a policy relating to the engagement of EFH Corp.’s independent auditor. The policy provides that in addition to the audit of the financial statements, related quarterly reviews and other audit services, and providing services necessary to complete SEC filings, EFH Corp.’s independent auditor may be engaged to provide non-audit services as described herein. Prior to engagement, all services to be rendered by the independent auditor must be authorized by the Audit Committee in accordance with pre-approval procedures which are defined in the policy. The pre-approval procedures require:
| 1. | The annual review and pre-approval by the Audit Committee of all anticipated audit and non-audit services; and |
| 2. | The quarterly pre-approval by the Audit Committee of services, if any, not previously approved and the review of the status of previously approved services. |
The Audit Committee may also approve certain on-going non-audit services not previously approved in the limited circumstances provided for in the SEC rules. All services performed by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates (Deloitte & Touche) for EFH Corp. in 2010 were pre-approved by the Audit Committee.
The policy defines those non-audit services which EFH Corp.’s independent auditor may also be engaged to provide as follows:
| 1. | Audit-related services, including: |
| a. | due diligence accounting consultations and audits related to mergers, acquisitions and divestitures; |
| b. | employee benefit plan audits; |
| c. | accounting and financial reporting standards consultation; |
| d. | internal control reviews, and |
| e. | attest services, including agreed-upon procedures reports that are not required by statute or regulation. |
| 2. | Tax-related services, including: |
| a. | tax compliance; |
| b. | general tax consultation and planning; |
| c. | tax advice related to mergers, acquisitions, and divestitures, and |
| d. | communications with and request for rulings from tax authorities. |
| 3. | Other services, including: |
| a. | process improvement, review and assurance; |
| b. | litigation and rate case assistance; |
| c. | forensic and investigative services, and |
| d. | training services. |
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The policy prohibits EFH Corp. from engaging its independent auditor to provide:
| 1. | Bookkeeping or other services related to EFH Corp.’s accounting records or financial statements; |
| 2. | Financial information systems design and implementation services; |
| 3. | Appraisal or valuation services, fairness opinions, or contribution-in-kind reports; |
| 4. | Actuarial services; |
| 5. | Internal audit outsourcing services; |
| 6. | Management or human resource functions; |
| 7. | Broker-dealer, investment advisor, or investment banking services; |
| 8. | Legal and expert services unrelated to the audit, and |
| 9. | Any other service that the Public Company Accounting Oversight Board determines, by regulation, to be impermissible. |
In addition, the policy prohibits EFH Corp.’s independent auditor from providing tax or financial planning advice to any officer of EFH Corp.
Compliance with the Audit Committee’s policy relating to the engagement of Deloitte & Touche is monitored on behalf of the Audit Committee by EFH Corp.’s chief accounting officer. Reports describing the services provided by Deloitte & Touche and fees for such services are provided to the Audit Committee no less often than quarterly.
For the years ended December 31, 2010 and 2009, fees billed to EFH Corp. by Deloitte & Touche were as follows:
| 2010 (a) | 2009 | |||||||
Audit Fees. Fees for services necessary to perform the annual audit, review SEC filings, fulfill statutory and other service requirements, provide comfort letters and consents | $ | 5,833,000 | $ | 7,549,000 | ||||
Audit-Related Fees.Fees for services including employee benefit plan audits, due diligence related to mergers, acquisitions and divestitures, accounting consultations and audits in connection with acquisitions, internal control reviews, attest services that are not required by statute or regulation, and consultation concerning financial accounting and reporting standards | 706,000 | 1,811,000 | ||||||
Tax Fees.Fees for tax compliance, tax planning, and tax advice related to mergers and acquisitions, divestitures, and communications with and requests for rulings from taxing authorities | 102,000 | 904,000 | ||||||
All Other Fees.Fees for services including process improvement reviews, forensic accounting reviews, litigation and rate case assistance, and training services | 0 | 0 | ||||||
Total | $ | 6,641,000 | $ | 10,264,000 | ||||
| (a) | See Notes 1 and 3 to Financial Statements for discussion of the deconsolidation of Oncor Holdings effective January 1, 2010. |
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| Item 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
(a) Oncor Holdings Financial Statements are presented pursuant to Rules 3–09 and 3–16 of Regulation S-X as Exhibit 99(e).
(b) Exhibits:
EFH Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2010
Exhibits | Previously Filed* With File Number | As | ||||||
| (2) | Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession | |||||||
| 2(a) | 1-12833 Form 8-K (filed February 26, 2007) | 2.1 | — | Agreement and Plan of Merger, dated February 25, 2007, by and among Energy Future Holdings Corp. (formerly known as TXU Corp.), Texas Energy Future Holdings Limited Partnership and Texas Energy Future Merger Sub Corp. | ||||
| (3(i)) | Articles of Incorporation | |||||||
| 3(a) | 1-12833 Form 8-K (filed October 11, 2007) | 3.1 | — | Restated Certificate of Formation of Energy Future Holdings Corp. | ||||
| (3(ii)) | By-laws | |||||||
| 3(b) | 1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 3(a) | — | Amended and Restated Bylaws of Energy Future Holdings Corp. | ||||
| (4) | Instruments Defining the Rights of Security Holders, Including Indentures**
Energy Future Holdings Corp. | |||||||
| 4(a) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 4(c) | — | Indenture (For Unsecured Debt Securities Series P), dated November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon, as trustee. | ||||
| 4(b) | 1-12833 Form 8-K (filed July 7, 2010) | 99.1 | — | Supplemental Indenture, dated July 1, 2010, to Indenture (For Unsecured Debt Securities Series P), dated November 1, 2004. | ||||
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| 4(c) | 1-12833 Form 10-K (2004)(filed March 16, 2005) | 4(q) | — | Officers’ Certificate, dated November 26, 2004, establishing the form and certain terms of Energy Future Holdings Corp.’s 5.55% Series P Senior Notes due 2014. | ||||
| 4(d) | — | Indenture (For Unsecured Debt Securities Series Q), dated November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon, as trustee. Energy Future Holdings Corp.’s Indentures for its Series R Senior Notes are not filed as it is substantially similar to this Indenture. | ||||||
| 4(e) | 1-12833 Form 10-K (2004) (filed March 16, 2005) | 4(r) | — | Officer’s Certificate, dated November 26, 2004, establishing the form and certain terms of Energy Future Holdings Corp.’s 6.50% Series Q Senior Notes due 2024. | ||||
| 4(f) | 1-12833 Form 10-K (2004) (filed March 16, 2005) | 4(s) | — | Officer’s Certificate, dated November 26, 2004, establishing the form and certain terms of Energy Future Holdings Corp.’s 6.55% Series R Senior Notes due 2034. | ||||
| 4(g) | 1-12833 Form 8-K (filed October 31, 2007) | 4.1 | — | Indenture, dated October 31, 2007, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon, as trustee, relating to Senior Notes due 2017 and Senior Toggle Notes due 2017. | ||||
| 4(h) | 1-12833 Form 10-K (2009) (filed February 19, 2010) | 4(f) | — | Supplemental Indenture, dated July 8, 2008, to Indenture, dated October 31, 2007. | ||||
| 4(i) | 1-12833 Form 10-Q (Quarter ended June 30, 2009) (filed August 4, 2009) | 4(a) | — | Second Supplemental Indenture, dated August 3, 2009, to Indenture, dated October 31, 2007. | ||||
| 4(j) | 1-12833 Form 8-K (filed July 30, 2010) | 99.1 | — | Third Supplemental Indenture, dated July 29, 2010, to Indenture, dated October 31, 2007. | ||||
| 4(k) | 1-12833 Form 8-K (filed November 20, 2009) | 4.1 | — | Indenture, dated November 16, 2009, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 9.75% Senior Secured Notes due 2019. | ||||
4(l) | 333-171253 Form S-4 (filed January 24, 2011) | 4(k) | — | Indenture, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 4(m) | 333-165860 Form S-3 (filed April 1, 2010) | 4(j) | — | First Supplemental Indenture, dated March 16, 2010, to Indenture, dated January 12, 2010. | ||||
| 4(n) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 4(a) | — | Second Supplemental Indenture, dated April 13, 2010, to Indenture, dated January 12, 2010. | ||||
| 4(o) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 4(b) | — | Third Supplemental Indenture, dated April 14, 2010, to Indenture, dated January 12, 2010. | ||||
| 4(p) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 4(c) | — | Fourth Supplemental Indenture, dated May 21, 2010, to Indenture, dated January 12, 2010. | ||||
| 4(q) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 4(d) | — | Fifth Supplemental Indenture, dated July 2, 2010, to Indenture, dated January 12, 2010. | ||||
| 4(r) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 4(e) | — | Sixth Supplemental Indenture, dated July 6, 2010, to Indenture, dated January 12, 2010. | ||||
| 4(s) | 333-171253 Form S-4 (filed January 24, 2011) | 4(r) | — | Seventh Supplemental Indenture, dated July 7, 2010, to Indenture, dated January 12, 2010. | ||||
| 4(t) | 1-12833 Form 8-K (filed January 19, 2010) | 4.2 | — | Registration Rights Agreement, dated January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and the initial purchasers named therein, relating to 10.000% Senior Secured Notes due 2020. | ||||
| 4(u) | 333-165860 Form S-3 (filed April 1, 2010) | 4(l) | — | Registration Rights Agreement, dated March 16, 2010, among Energy Future Holdings Corp., the guarantors named therein and the initial purchasers named therein, relating to 10.000% Senior Secured Notes due 2020. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 4(v) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 4(h) | — | Registration Rights Agreement, dated April 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and the initial purchasers named therein, relating to 10.000% Senior Secured Notes due 2020. | ||||
| 4(w) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 4(i) | — | Registration Rights Agreement, dated April 13, 2010, among Energy Future Holdings Corp., the guarantors named therein and the initial purchasers named therein, relating to 10.000% Senior Secured Notes due 2020. | ||||
| 4(x) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 4(j) | — | Registration Rights Agreement, dated May 20, 2010, among Energy Future Holdings Corp., the guarantors named therein and the initial purchasers named therein, relating to 10.000% Senior Secured Notes due 2020. | ||||
| 4(y) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 4(k) | — | Registration Rights Agreement, dated July 2, 2010, among Energy Future Holdings Corp., the guarantors named therein and the initial purchasers named therein, relating to 10.000% Senior Secured Notes due 2020. | ||||
| 4(z) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 4(l) | — | Registration Rights Agreement, dated July 6, 2010, among Energy Future Holdings Corp., the guarantors named therein and the initial purchasers named therein, relating to 10.000% Senior Secured Notes due 2020. | ||||
| 4(aa) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 4(m) | — | Registration Rights Agreement, dated July 7, 2010, among Energy Future Holdings Corp., the guarantors named therein and the initial purchasers named therein, relating to 10.000% Senior Secured Notes due 2020. | ||||
| Oncor Electric Delivery Company LLC | ||||||||
| 4(bb) | 333-100240 Form S-4(filed October 2, 2002) | 4(a) | — | Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon, as trustee. | ||||
| 4(cc) | 1-12833 Form 8-K (filed October 31, 2005) | 10.1 | — | Supplemental Indenture No. 1, dated October 25, 2005, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 4(dd) | 333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 4(b) | — | Supplemental Indenture No. 2, dated October 25, 2005, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon. | ||||
| 4(ee) | 333-100240 Form S-4 (filed October 2, 2002) | 4(b) | — | Officer’s Certificate, dated May 6, 2002, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes due 2012 and 7.000% Senior Notes due 2032. | ||||
| 4(ff) | 333-100242 Form S-4 (filed October 2, 2002) | 4(a) | — | Indenture (for Unsecured Debt Securities), dated August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon, as trustee. | ||||
| 4(gg) | 333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 4(c) | — | Supplemental Indenture No. 1, dated May 15, 2008, to Indenture and Deed of Trust, dated August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York. | ||||
| 4(hh) | 333-100242 Form S-4 (filed October 2, 2002) | 4(b) | — | Officer’s Certificate, dated August 30, 2002, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 5% Debentures due 2007 and 7% Debentures due 2022. | ||||
| 4(ii) | 333-106894 Form S-4 (filed July 9, 2003) | 4(c) | — | Officer’s Certificate, dated December 20, 2002, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes due 2015 and 7.250% Senior Notes due 2023. | ||||
| 4(jj) | 333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 4(a) | — | Deed of Trust, Security Agreement and Fixture Filing, dated May 15, 2008, by Oncor Electric Delivery Company LLC, as grantor, to and for the benefit of, The Bank of New York Mellon Trust, as collateral agent and trustee. | ||||
| 4(kk) | 333-100240 Form 10-K (2008) (filed March 2, 2009) | 4(n) | — | First Amendment, dated March 2, 2009, to Deed of Trust, Security Agreement and Fixture Filing, dated May 15, 2008. | ||||
| 4(ll) | 333-100240 Form 8-K (filed September 3, 2010) | 10.1 | — | Second Amendment, dated September 3, 2010, to Deed of Trust, Security Agreement and Fixture Filing, dated September 3, 2010. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 4(mm) | 333-100242 Form 8-K (filed September 9, 2008) | 4.1 | — | Officer’s Certificate, dated September 8, 2008, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 5.95% Senior Secured Notes due 2013, 6.80% Senior Secured Notes due 2018 and 7.50% Senior Secured Notes due 2038. | ||||
| 4(nn) | 333-100240 Form 8-K (filed September 16, 2010) | 4.1 | — | Officer’s Certificate, dated September 13, 2010, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 5.25% Senior Secured Notes due 2040. | ||||
| 4(oo) | 333-100240 Form 8-K (filed September 16, 2010) | 4.2 | — | Registration Rights Agreement, dated September 13, 2010, among Oncor Electric Delivery Company LLC, Barclays Capital Inc., Citigroup Global Markets Inc., Banc of America Securities LLC and Credit Suisse Securities (USA) LLC, as representatives of the initial purchasers of Oncor Electric Delivery Company LLC’s 5.25% Senior Secured Notes due 2040, relating to 5.25% Senior Secured Notes due 2040. | ||||
| 4(pp) | 333-100240 Form 8-K (filed October 12, 2010) | 4.1 | — | Officer’s Certificate, dated October 8, 2010, establishing the form and certain terms of Oncor Electric Delivery Company LLC’s 5.00% Senior Secured Notes due 2017 and 5.75% Senior Secured Notes due 2020. | ||||
| 4(qq) | 333-100240 Form 8-K (filed October 12, 2010) | 4.2 | — | Registration Rights Agreement, dated October 8, 2010, among Oncor Electric Delivery Company LLC and the dealer managers named therein, relating to 5.00% Senior Secured Notes due 2017 and 5.75% Senior Secured Notes due 2020. | ||||
| Texas Competitive Electric Holdings Company LLC | ||||||||
| 4(rr) | 333-108876 Form 8-K(filed October 31, 2007) | 4.2 | — | Indenture, dated October 31, 2007, among Texas Competitive Electric Holdings Company LLC and TCEH Finance, Inc., the guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.25% Senior Notes due 2015. | ||||
| 4(ss) | 1-12833 Form 8-K(filed December 12, 2007) | 4.1 | — | First Supplemental Indenture, dated December 6, 2007, to Indenture, dated October 31, 2007, relating to Texas Competitive Electric Holdings Company LLC’s and TCEH Finance, Inc.’s 10.25% Senior Notes due 2015, Series B, and 10.50%/11.25% Senior Toggle Notes due 2016. | ||||
| 4(tt) | 1-12833 Form 10-Q(Quarter ended June 30, 2009) (filed August 4, 2009) | 4(b) | — | Second Supplemental Indenture, dated August 3, 2009, to Indenture, dated October 31, 2007, relating to Texas Competitive Electric Holdings Company LLC’s and TCEH Finance, Inc.’s 10.25% Senior Notes due 2015, 10.25% Senior Notes due 2015, Series B, and 10.50%/11.25% Senior Toggle Notes due 2016. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 4(uu) | 1-12833 Form 8-K(filed October 8, 2010) | 4.1 | — | Indenture, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC and TCEH Finance, Inc., the guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 15% Senior Secured Second Lien Notes due 2021. | ||||
| 4(vv) | 1-12833 Form 8-K(filed October 26, 2010) | 4.1 | — | First Supplemental Indenture, dated October 20, 2010, to the Indenture, dated October 6, 2010. | ||||
| 4(ww) | 1-12833 Form 8-K(filed November 17, 2010) | 4.1 | — | Second Supplemental Indenture, dated November 15, 2010, to the Indenture, dated October 6, 2010. | ||||
| 4(xx) | 1-12833 Form 8-K(filed October 8, 2010) | 4.3 | — | Second Lien Pledge Agreement, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as collateral agent for the benefit of the second lien secured parties. | ||||
| 4(yy) | 1-12833 Form 8-K(filed October 8, 2010) | 4.4 | — | Second Lien Security Agreement, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the subsidiary guarantors named therein and The Bank Of New York Mellon Trust Company, N.A., as collateral agent and as the initial second priority representative for the benefit of the second lien secured parties. | ||||
| 4(zz) | 1-12833 Form 8-K(filed October 8, 2010) | 4.5 | — | Second Lien Intercreditor Agreement, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the subsidiary guarantors named therein, Citibank, N.A., as collateral agent for the senior collateral agent and the administrative agent, The Bank of New York Mellon Trust Company, N.A., as the initial second priority representative. | ||||
| 4(aaa) | — | Form of Second Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of The Bank of New York Mellon Trust Company, N.A., as Collateral Agent and Initial Second Priority Representative for the benefit of the Second Lien Secured Parties, as Beneficiary. | ||||||
| 4(bbb) | 1-12833 Form 8-K(filed October 8, 2010) | 4.2 | — | Registration Rights Agreement, dated October 6, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the holders named therein and the guarantors named therein, relating to 15% Senior Secured Second Lien Notes due 2021. | ||||
| 4(ccc) | 1-12833 Form 8-K(filed October 26, 2010) | 4.2 | — | Registration Rights Agreement, dated October 20, 2010, among Texas Competitive Electric Holdings Company LLC, TCEH Finance, Inc., the initial purchasers and the guarantors named therein, relating to 15% Senior Secured Second Lien Notes due 2021, Series B. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| Energy Future Intermediate Holding Company LLC | ||||||||
| 4(ddd) | 1-12833 Form 8-K(filed November 20, 2009) | 4.2 | — | Indenture, dated November 16, 2009, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee. | ||||
| 4(eee) | 1-12833 Form 8-K(filed August 18, 2010) | 4.1 | — | Indenture, dated August 17, 2010, among Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 10.000% Senior Secured Notes due 2020. | ||||
(10) | Material Contracts | |||||||
| Management Contracts; Compensatory Plans, Contracts and Arrangements | ||||||||
| 10(a) | 1-12833 Form 8-K (filed May 23, 2005) | 10.6 | — | Energy Future Holdings Corp. Executive Change in Control Policy effective May 20, 2005. | ||||
| 10(b) | 333-153529 Amendment No. 2 to Form S-4 (filed December 23, 2008) | 10(p) | — | Amendment to the Energy Future Holdings Corp. Executive Change in Control Policy, dated December 23, 2008. | ||||
| 10(c) | — | Amendment to the Energy Future Holdings Corp. Executive Change in Control Policy, dated December 20, 2010. | ||||||
| 10(d) | 1-12833 Form 8-K (filed May 23, 2005) | 10.7 | — | Energy Future Holdings Corp. 2005 Executive Severance Plan and Summary Plan Description. | ||||
| 10(e) | 333-153529 Amendment No. 2 to Form S-4 (filed December 23, 2008) | 10(n) | — | Amendment to the Energy Future Holdings Corp. 2005 Executive Severance Plan and Summary Plan Description, dated December 23, 2008. | ||||
| 10(f) | — | Amendment to the Energy Future Holdings Corp. 2005 Executive Severance Plan and Summary Plan Description, dated December 10, 2010. | ||||||
| 10(g) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(a) | — | 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its affiliates. | ||||
| 10(h) | 1-12833 Form 10-K (2009) (filed February 19, 2010) | 10(ii) | — | Amendment No. 1 to the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates, dated July 14, 2009, effective as of December 23, 2008. | ||||
| 10(i) | — | EFH Executive Annual Incentive Plan, effective as of January 1, 2010. | ||||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 10(j) | 1-12833 Form 10-K (2008) (filed March 3, 2009) | 10(q) | — | EFH Second Supplemental Retirement Plan, effective as of October 10, 2007. | ||||
| 10(k) | 1-12833 Form 10-K (2009) (filed February 19, 2010) | 10(ee) | — | Amendment to EFH Second Supplemental Retirement Plan, dated July 31, 2009. | ||||
| 10(l) | — | Second Amendment to EFH Second Supplemental Retirement Plan, dated April 9, 2010 with effect as of January 1, 2010. | ||||||
| 10(m) | — | Third Amendment to EFH Second Supplemental Retirement Plan, dated April 21, 2010 with effect as of January 1, 2010. | ||||||
| 10(n) | 1-12833 Form 10-K (2009) (filed February 19, 2010) | 10(dd) | — | EFH Salary Deferral Program, effective January 1, 2010. | ||||
| 10(o) | — | Amendment to EFH Salary Deferral Program, effective January 20, 2011. | ||||||
| 10(p) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(b) | — | Registration Rights Agreement, dated October 10, 2007, among Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp. and the stockholders party thereto. | ||||
| 10(q) | 1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 10(a) | — | Form of Stockholder’s Agreement (for Directors) among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and the stockholder party thereto. | ||||
| 10(r) | 1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 10(b) | — | Form of Sale Participation Agreement (for Directors) between Texas Energy Future Holdings Limited Partnership and the stockholder party hereto. | ||||
| 10(s) | 1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008) | 10(f) | — | Form of Management Stockholder’s Agreement (For Executive Officers) among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and the stockholder party thereto. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 10(t) | 1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008) | 10(g) | — | Form of Sale Participation Agreement (For Executive Officers) between Texas Energy Future Holdings Limited Partnership and the stockholder party thereto. | ||||
| 10(u) | 1-12833 Form 10-K (2009) (filed February 19, 2010) | 10(m) | — | Form of Amended and Restated Non-Qualified Stock Option Agreement (For Executive Officers) between Energy Future Holdings Corp. and the optionee thereto. | ||||
| 10(v) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(f) | — | Energy Future Holdings Corp. Non-Employee Director Compensation Arrangements. | ||||
| 10(w) | 1-12833 Form 10-K (2009) (filed February 19, 2010) | 10(nn) | — | Consulting Agreement, dated February 18, 2010, between Energy Future Holdings Corp. and Donald L. Evans. | ||||
| 10(x) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(p) | — | Employment Agreement, dated January 6, 2008, between Energy Future Holdings Corp. and John Young. | ||||
| 10(y) | 1-12833 Form 10-K (2009) (filed February 19, 2010) | 10(jj) | — | Employment Arrangement with John Young. | ||||
| 10(z) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(r) | — | Management Stockholder’s Agreement, dated February 1, 2008, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and John Young. | ||||
| 10(aa) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(s) | — | Sale Participation Agreement, dated February 1, 2008, between Texas Energy Future Holdings Limited Partnership and John F. Young. | ||||
| 10(bb) | 1-12833 Form 10-K (2009) (filed February 19, 2010) | 10(hh) | — | Restricted Stock Unit Award Agreement, effective as of January 6, 2008, between Energy Future Holdings Corp. and John Young. | ||||
| 10(cc) | 1-12833 Form 10-K (2008) (filed March 3, 2009) | 10(y) | — | Amended and Restated Employment Agreement, dated July 1, 2008, between Energy Future Holdings Corp. and Paul M. Keglevic. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 10(dd) | — | Employment Arrangement with Paul Keglevic. | ||||||
| 10(ee) | — | Deferred Share Agreement, dated July 1, 2008, between Energy Future Holdings Corp. and Paul Keglevic. | ||||||
| 10(ff) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 10(d) | — | Amended and Restated Employment Agreement, effective January 1, 2010, between Luminant Holding Company LLC, Energy Future Holdings Corp. and David A. Campbell. | ||||
| 10(gg) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(y) | — | Additional Payment Agreement, dated October 10, 2007, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership, Texas Competitive Electric Holdings Company LLC and David Campbell. | ||||
| 10(hh) | — | Deferred Share Agreement, dated May 20, 2008, between Energy Future Holdings Corp. and David Campbell. | ||||||
| 10(ii) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 10(c) | — | Amended and Restated Employment Agreement, effective January 1, 2010, between TXU Retail Company LLC, Energy Future Holdings Corp. and James A. Burke. | ||||
| 10(jj) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(ff) | — | Additional Payment Agreement, dated October 10, 2007, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership, Texas Competitive Electric Holdings Company LLC and James Burke. | ||||
| 10(kk) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(nn) | — | Deferred Share Agreement, dated October 9, 2007, between Texas Energy Future Holdings Limited Partnership and James Burke. | ||||
| 10(ll) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 10(a) | — | Amended and Restated Employment Agreement, effective January 1, 2010, between EFH Corporate Services Company, Energy Future Holdings Corp. and Robert C. Walters. | ||||
| 10(mm) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 10(b) | — | Amended and Restated Employment Agreement, effective January 1, 2010, between Luminant Holding Company LLC, Energy Future Holdings Corp. and Mark Allen McFarland. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 10(nn) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 10(e) | — | Employment Agreement, effective January 1, 2010, between EFH Corporate Services Company, Energy Future Holdings Corp. and Richard J. Landy. | ||||
| 10(oo) | 1-12833 Form 10-K (2009) (filed February 19, 2010) | 10(gg) | — | Energy Future Holdings Corp. Key Employee Non-Qualified Stock Option Agreement, dated January 26, 2010, between Energy Future Holdings Corp. and Richard Landy. | ||||
| 10(pp) | 1-12833 Form 10-Q (Quarter ended June 30, 2010) (filed August 2, 2010) | 10(f) | — | Employment Agreement, effective January 1, 2010, between EFH Corporate Services Company, Energy Future Holdings Corp. and Joel D. Kaplan. | ||||
| 10(qq) | 1-12833 Form 10-K (2009) (filed February 19, 2010) | 10(ff) | — | Energy Future Holdings Corp. Key Employee Non-Qualified Stock Option Agreement, dated December 17, 2009, between Energy Future Holdings Corp. and Joel Kaplan. | ||||
| Credit Agreements and Related Agreements | ||||||||
| 10(rr) | 333-100240 Form 10-Q (Quarter ended September 30, 2007) (filed November 14, 2007) | 10(a) | — | $2,000,000,000 Revolving Credit Agreement, dated October 10, 2007, among Oncor Electric Delivery Company LLC, as the borrower; the several lenders from time to time parties thereto; JPMorgan Chase Bank, N.A., as administrative agent, fronting bank and swingline lender, Citibank, N.A., as syndication agent and fronting bank; Credit Suisse, Cayman Islands Branch, Goldman Sachs Credit Partners L.P., Lehman Commercial Paper Inc., Morgan Stanley Senior Funding, Inc., as co-documentation agents; J.P. Morgan Securities Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Goldman Sachs Credit Partners L.P., Lehman Brothers Inc. and Morgan Stanley Senior Funding, Inc., as joint lead arrangers and bookrunners. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 10(ss) | 333-171253 Post-Effective Amendment #1 to Form S-4 (filed February 7, 2011) | 10(rr) | — | $24,500,000,000 Credit Agreement, dated October 10, 2007, among Energy Future Competitive Holdings Company; Texas Competitive Electric Holdings Company LLC, as the borrower; the several lenders from time to time parties thereto; Citibank, N.A., as administrative agent, collateral agent, swingline lender, revolving letter of credit issuer and deposit letter of credit issuer; Goldman Sachs Credit Partners L.P., as posting agent, posting syndication agent and posting documentation agent; JPMorgan Chase Bank, N.A., as syndication agent and revolving letter of credit issuer; Citigroup Global Markets Inc., J.P. Morgan Securities Inc., Goldman Sachs Credit Partners L.P., Lehman Brothers Inc., Morgan Stanley Senior Funding, Inc. and Credit Suisse Securities (USA) LLC, as joint lead arrangers and bookrunners; Goldman Sachs Credit Partners L.P., as posting lead arranger and bookrunner; Credit Suisse, Goldman Sachs Credit Partners L.P., Lehman Commercial Paper Inc., Morgan Stanley Senior Funding, Inc., as co-documentation agents; and J. Aron & Company, as posting calculation agent. | ||||
| 10(tt) | 1-12833 Form 8-K (filed August 10, 2009) | 10.1 | — | Amendment No. 1, dated August 7, 2009, to the $24,500,000,000 Credit Agreement. | ||||
| 10(uu) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(ss) | — | Guarantee, dated October 10, 2007, by the guarantors party thereto in favor of Citibank, N.A., as collateral agent for the benefit of the secured parties under the $24,500,000,000 Credit Agreement, dated October 10, 2007. | ||||
| 10(vv) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(vv) | — | Form of Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing to Fidelity National Title Insurance Company, as trustee, for the benefit of Citibank, N.A., as beneficiary. | ||||
| 10(ww) | 1-12833 Form 8-K (filed August 10, 2009) | 10.2 | — | Amended and Restated Collateral Agency and Intercreditor Agreement, dated October 10, 2007, as amended and restated as of August 7, 2009, among Energy Future Competitive Holdings Company; Texas Competitive Electric Holdings Company LLC; the subsidiary guarantors party thereto; Citibank, N.A., as administrative agent and collateral agent; Credit Suisse Energy LLC, J. Aron & Company, Morgan Stanley Capital Group Inc., Citigroup Energy Inc., each as a secured hedge counterparty; and any other person that becomes a secured party pursuant thereto. | ||||
| 10(xx) | 1-12833 Form 8-K (filed August 10, 2009) | 10.3 | — | Amended and Restated Security Agreement, dated October 10, 2007, as amended and restated as of August 7, 2009, among Texas Competitive Electric Holdings Company LLC, the subsidiary grantors party thereto, and Citibank, N.A., as collateral agent for the benefit of the first lien secured parties, including the secured parties under the $24,500,000,000 Credit Agreement, dated October 10, 2007. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
10(yy) | 1-12833 Form 8-K (filed August 10, 2009) | 10.4 | — | Amended and Restated Pledge Agreement, dated October 10, 2007, as amended and restated as of August 7, 2009, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary pledgors party thereto, and Citibank, N.A., as collateral agent for the benefit first lien secured parties, including the secured parties under the $24,500,000,000 Credit Agreement, dated October 10, 2007. | ||||
10(zz) | 1-12833 Form 8-K (filed November 20, 2009) | 4.3 | — | Pledge Agreement, dated November 16, 2009, made by Energy Future Intermediate Holding Company LLC and the additional pledgers to The Bank of New York Mellon Trust Company, N.A., as collateral trustee for the holders of parity lien obligations. | ||||
10(aaa) | 1-12833 Form 8-K (filed November 20, 2009) | 4.4 | — | Collateral Trust Agreement, dated November 16, 2009, among Energy Future Intermediate Holding Company LLC, The Bank of New York Mellon Trust Company, N.A., as first lien trustee and as collateral trustee, and the other secured debt representatives party thereto. | ||||
| Other Material Contracts | ||||||||
10(bbb) | 1-12833 Form 10-K (2003) (filed March 15, 2004) | 10(qq) | — | Lease Agreement, dated February 14, 2002, between State Street Bank and Trust Company of Connecticut, National Association, a owner trustee of ZSF/Dallas Tower Trust, a Delaware grantor trust, as lessor and EFH Properties Company, as Lessee (Energy Plaza Property). | ||||
10(ccc) | 1-12833 Form 10-Q (Quarter ended June 30, 2007) (filed August 9, 2007) | 10.1 | — | First Amendment, dated June 1, 2007, to Lease Agreement, dated February 14, 2002. | ||||
10(ddd) | 333-100240 Form 10-K (2004) (filed March 23, 2005) | 10(i) | — | Agreement, dated March 10, 2005, between Oncor Electric Delivery Company LLC and TXU Energy Company LLC, allocating to Oncor Electric Delivery Company LLC the pension and post-retirement benefit costs for all Oncor Electric Delivery Company LLC employees who had retired or had terminated employment as vested employees prior to January 1, 2002. | ||||
10(eee) | 1-12833 Form 10-K (2006) (filed March 2, 2007) | 10(iii) | — | Amended and Restated Transaction Confirmation by Generation Development Company LLC, dated February 2007 (subsequently assigned to Texas Competitive Electric Holdings Company LLC on October 10, 2007) (confidential treatment has been requested for portions of this exhibit). | ||||
10(fff) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(eee) | — | Stipulation as approved by the PUCT in Docket No. 34077. | ||||
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Exhibits | Previously Filed* With File Number | As Exhibit | ||||||
10(ggg) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(fff) | — | Amendment to Stipulation Regarding Section 1, Paragraph 35 and Exhibit B in Docket No. 34077. | ||||
10(hhh) | 333-100240 Form 10-K (2010) (filed February 18, 2011) | 10(ae) | — | PUCT Order on Rehearing in Docket No. 34077. | ||||
10(iii) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(sss) | — | ISDA Master Agreement, dated October 25, 2007, between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P. | ||||
10(jjj) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(ttt) | — | Schedule to the ISDA Master Agreement, dated October 25, 2007, between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P. | ||||
10(kkk) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(uuu) | — | Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P. | ||||
10(lll) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(vvv) | — | ISDA Master Agreement, dated October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International. | ||||
10(mmm) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(www) | — | Schedule to the ISDA Master Agreement, dated October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International. | ||||
10(nnn) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(xxx) | — | Form of Confirmation between Texas Competitive Electric Holdings Company LLC and Credit Suisse International. | ||||
10(ooo) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(yyy) | — | Management Agreement, dated October 10, 2007, among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership, Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P., Goldman, Sachs & Co. and Lehman Brothers Inc. | ||||
10(ppp) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(cccc) | — | Indemnification Agreement, dated October 10, 2007, among Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp., Kohlberg Kravis Roberts & Co., L.P., TPG Capital, L.P. and Goldman, Sachs & Co. | ||||
10(qqq) | 333-100240 Form 8-K (filed August 13, 2008) | 10.1 | — | Contribution and Subscription Agreement, dated August 12, 2008, between Oncor Electric Delivery Company LLC and Texas Transmission Investment LLC. | ||||
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Exhibits | Previously Filed* With File Number | As Exhibit | ||||||
| 10(rrr) | 1-12833 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008) | 10(g) | — | Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Holdings Company LLC, dated November 5, 2008. | ||||
| 10(sss) | 333-100240 Form 10-K (2008) (filed March 3, 2009) | 3(c) | — | Amendment No. 1, dated February 18, 2009, to Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery LLC. | ||||
| 10(ttt) | 333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008) | 4(c) | — | Investor Rights Agreement, dated November 5, 2008, among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp. | ||||
| 10(uuu) | 333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008) | 4(d) | — | Registration Rights Agreement, dated November 5, 2008, among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp. | ||||
| 10(vvv) | 333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008) | 10(b) | — | Amended and Restated Tax Sharing Agreement, dated November 5, 2008, among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Oncor Management Investment LLC, Texas Transmission Investment LLC, Energy Future Intermediate Holding Company LLC and Energy Future Holdings Corp. | ||||
| (12) | Statement Regarding Computation of Ratios | |||||||
| 12(a) | — | Computation of Ratio of Earnings to Fixed Charges. | ||||||
| (21) | Subsidiaries of the Registrant | |||||||
| 21(a) | — | Subsidiaries of Energy Future Holdings Corp. | ||||||
| (23) | Consent of Experts | |||||||
| 23(a) | — | Consent of Deloitte & Touche LLP, an independent registered public accounting firm, relating to the consolidated financial statements of Energy Future Holdings Corp. | ||||||
| 23(b) | — | Consent of Deloitte & Touche LLP, an independent registered public accounting firm, relating to the consolidated financial statements of Oncor Electric Delivery Holdings Company LLC | ||||||
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Exhibits | Previously Filed* With File Number | As Exhibit | ||||||
| (31) | Rule 13a - 14(a)/15d - 14(a) Certifications | |||||||
| 31(a) | — | Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||||||
| 31(b) | — | Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||||||
| 32 | Section 1350 Certifications | |||||||
| 32(a) | — | Certification of John Young, principal executive officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||||||
| 32(b) | — | Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp., pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||||||
| (99) | Additional Exhibits | |||||||
| 99(a) | 33-55408 Post-Effective Amendment No. 1 to Form S-3 (filed July, 1993) | 99(b) | — | Amended Agreement dated January 30, 1990, between Energy Future Competitive Holdings Company and Tex-La Electric Cooperative of Texas, Inc. | ||||
| 99(b) | — | Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2010 and 2009. | ||||||
| 99(c) | — | Texas Competitive Electric Holdings Company LLC Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2010 and 2009. | ||||||
| 99(d) | — | Energy Future Intermediate Holding Company LLC Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2010 and 2009. | ||||||
| 99(e) | — | Oncor Electric Delivery Holdings Company LLC financial statements presented pursuant to Rules 3–09 and 3–16 of Regulation S–X. | ||||||
| * | Incorporated herein by reference |
| ** | Certain instruments defining the rights of holders of long-term debt of the Company’s subsidiaries included in the financial statements filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10 percent of the total assets of the Company and its subsidiaries on a consolidated basis. The Company hereby agrees, upon request of the SEC, to furnish a copy of any such omitted instrument. |
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Energy Future Holdings Corp. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENERGY FUTURE HOLDINGS CORP. | ||||
| Date: February 17, 2011 | By | /s/ JOHN F. YOUNG | ||
| (John F. Young, President and Chief Executive Officer) | ||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Energy Future Holdings Corp. and in the capacities and on the date indicated.
Signature | Title | Date | ||
/s/ JOHN F. YOUNG | Principal Executive | February 17, 2011 | ||
| (John F. Young, President and Chief Executive Officer) | Officer and Director | |||
/s/ PAUL M. KEGLEVIC | Principal Financial Officer | February 17, 2011 | ||
| (Paul M. Keglevic, Executive Vice President and Chief Financial Officer) | ||||
/s/ STANLEY J. SZLAUDERBACH | Principal Accounting Officer | February 17, 2011 | ||
| (Stanley J. Szlauderbach, Senior Vice President and Controller) | ||||
/s/ DONALD L. EVANS | Director | February 17, 2011 | ||
| (Donald L. Evans, Chairman of the Board) | ||||
/s/ ARCILIA C. ACOSTA | Director | February 17, 2011 | ||
| (Arcilia C. Acosta) | ||||
/s/ DAVID BONDERMAN | Director | February 17, 2011 | ||
| (David Bonderman) | ||||
/s/ THOMAS D. FERGUSON | Director | February 17, 2011 | ||
| (Thomas D. Ferguson) | ||||
/s/ FREDERICK M. GOLTZ | Director | February 17, 2011 | ||
| (Frederick M. Goltz) | ||||
/s/ JAMES R. HUFFINES | Director | February 17, 2011 | ||
| (James R. Huffines) | ||||
/s/ SCOTT LEBOVITZ | Director | February 17, 2011 | ||
| (Scott Lebovitz) | ||||
/s/ JEFFREY LIAW | Director | February 17, 2011 | ||
| (Jeffrey Liaw) | ||||
/s/ MARC S. LIPSCHULTZ | Director | February 17, 2011 | ||
| (Marc S. Lipschultz) | ||||
/s/ MICHAEL MACDOUGALL | Director | February 17, 2011 | ||
| (Michael MacDougall) | ||||
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Signature | Title | Date | ||
/S/ LYNDON L. OLSON, JR. | Director | February 17, 2011 | ||
| (Lyndon L. Olson, Jr.) | ||||
/S/ KENNETH PONTARELLI | Director | February 17, 2011 | ||
| (Kenneth Pontarelli) | ||||
/S/ WILLIAM K. REILLY | Director | February 17, 2011 | ||
| (William K. Reilly) | ||||
/S/ JONATHAN D. SMIDT | Director | February 17, 2011 | ||
| (Jonathan D. Smidt) | ||||
/S/ KNEELAND YOUNGBLOOD | Director | February 17, 2011 | ||
| (Kneeland Youngblood) | ||||
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Exhibit 4(d)
TXU CORP.
TO
THE BANK OF NEW YORK
Trustee
Indenture
(For Unsecured Debt Securities Series Q)
Dated as of November 1, 2004
Table of Contents
TABLE OF CONTENTS
PARTIES | 1 | |||
RECITAL OF THE COMPANY | 1 | |||
ARTICLE ONE Definitions and Other Provisions of General Application | 1 | |||
SECTION 101. Definitions. | 1 | |||
Act | 2 | |||
Affiliate | 2 | |||
Authenticating Agent | 2 | |||
Authorized Officer | 2 | |||
Board of Directors | 2 | |||
Board Resolution | 2 | |||
Business Day | 2 | |||
Commission | 2 | |||
Company | 3 | |||
Company Request or Company Order | 3 | |||
Corporate Trust Office | 3 | |||
corporation | 3 | |||
Defaulted Interest | 3 | |||
Discount Security | 3 | |||
Dollar or $ | 3 | |||
Eligible Obligations | 3 | |||
Event of Default | 3 | |||
Governmental Authority | 3 | |||
Government Obligations | 3 | |||
Holder | 4 | |||
Indenture | 4 | |||
Interest Payment Date | 4 | |||
Maturity | 4 | |||
Officer’s Certificate | 4 | |||
Opinion of Counsel | 4 | |||
Outstanding | 4 | |||
Paying Agent | 5 | |||
Periodic Offering | 5 | |||
Person | 6 | |||
Place of Payment | 6 | |||
Predecessor Security | 6 | |||
Redemption Date | 6 | |||
Redemption Price | 6 | |||
Regular Record Date | 6 | |||
Required Currency | 6 | |||
Responsible Officer | 6 | |||
Securities | 6 | |||
Security Register and Security Registrar | 6 | |||
Note: This table of contents shall not, for any purpose, be deemed to be part of the Indenture.
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Special Record Date | 6 | |||
Stated Interest Rate | 6 | |||
Stated Maturity | 7 | |||
Subsidiary | 7 | |||
Tranche | 7 | |||
Trust Indenture Act | 7 | |||
Trustee | 7 | |||
United States | 7 | |||
SECTION 102. Compliance Certificates and Opinions. | 7 | |||
SECTION 103. Form of Documents Delivered to Trustee. | 8 | |||
SECTION 104. Acts of Holders. | 9 | |||
SECTION 105. Notices, etc. to Trustee and Company. | 10 | |||
SECTION 106. Notice to Holders of Securities; Waiver. | 11 | |||
SECTION 107. Conflict with Trust Indenture Act. | 12 | |||
SECTION 108. Effect of Headings and Table of Contents. | 12 | |||
SECTION 109. Successors and Assigns. | 12 | |||
SECTION 110. Separability Clause. | 12 | |||
SECTION 111. Benefits of Indenture. | 12 | |||
SECTION 112. Governing Law. | 12 | |||
SECTION 113. Legal Holidays. | 12 | |||
ARTICLE TWO Security Forms | 13 | |||
SECTION 201. Forms Generally. | 13 | |||
SECTION 202. Form of Trustee’s Certificate of Authentication. | 13 | |||
ARTICLE THREE The Securities | 14 | |||
SECTION 301. Amount Unlimited; Issuable in Series. | 14 | |||
SECTION 302. Denominations. | 17 | |||
SECTION 303. Execution, Authentication, Delivery and Dating. | 17 | |||
SECTION 304. Temporary Securities. | 20 | |||
SECTION 305. Registration, Registration of Transfer and Exchange. | 21 | |||
SECTION 306. Mutilated, Destroyed, Lost and Stolen Securities. | 22 | |||
SECTION 307. Payment of Interest; Interest Rights Preserved. | 23 | |||
SECTION 308. Persons Deemed Owners. | 24 | |||
SECTION 309. Cancellation by Security Registrar. | 24 | |||
SECTION 310. Computation of Interest. | 24 | |||
SECTION 311. Payment to Be in Proper Currency. | 24 | |||
SECTION 312. Extension of Interest Payment. | 25 | |||
ARTICLE FOUR Redemption of Securities | 25 | |||
SECTION 401. Applicability of Article. | 25 | |||
SECTION 402. Election to Redeem; Notice to Trustee. | 25 | |||
SECTION 403. Selection of Securities to Be Redeemed. | 25 | |||
SECTION 404. Notice of Redemption. | 26 | |||
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Table of Contents
SECTION 405. Securities Payable on Redemption Date. | 27 | |||
SECTION 406. Securities Redeemed in Part. | 28 | |||
ARTICLE FIVE Sinking Funds | 28 | |||
SECTION 501. Applicability of Article. | 28 | |||
SECTION 502. Satisfaction of Sinking Fund Payments with Securities. | 28 | |||
SECTION 503. Redemption of Securities for Sinking Fund. | 29 | |||
ARTICLE SIX Covenants | 30 | |||
SECTION 601. Payment of Principal, Premium and Interest. | 30 | |||
SECTION 602. Maintenance of Office or Agency. | 30 | |||
SECTION 603. Money for Securities Payments to Be Held in Trust. | 30 | |||
SECTION 604. Corporate Existence. | 32 | |||
SECTION 605. Maintenance of Properties. | 32 | |||
SECTION 606. Annual Officer’s Certificate as to Compliance. | 32 | |||
SECTION 607. Waiver of Certain Covenants. | 32 | |||
SECTION 608. Limitation on Liens. | 33 | |||
ARTICLE SEVEN Satisfaction and Discharge | 35 | |||
SECTION 701. Satisfaction and Discharge of Securities. | 35 | |||
SECTION 702. Satisfaction and Discharge of Indenture. | 38 | |||
SECTION 703. Application of Trust Money. | 38 | |||
ARTICLE EIGHT Events of Default; Remedies | 39 | |||
SECTION 801. Events of Default. | 39 | |||
SECTION 802. Acceleration of Maturity; Rescission and Annulment. | 40 | |||
SECTION 803. Collection of Indebtedness and Suits for Enforcement by Trustee. | 41 | |||
SECTION 804. Trustee May File Proofs of Claim. | 42 | |||
SECTION 805. Trustee May Enforce Claims Without Possession of Securities. | 42 | |||
SECTION 806. Application of Money Collected. | 43 | |||
SECTION 807. Limitation on Suits. | 43 | |||
SECTION 808. Unconditional Right of Holders to Receive Principal, Premium and Interest. | 44 | |||
SECTION 809. Restoration of Rights and Remedies. | 44 | |||
SECTION 810. Rights and Remedies Cumulative. | 44 | |||
SECTION 811. Delay or Omission Not Waiver. | 44 | |||
SECTION 812. Control by Holders of Securities. | 44 | |||
SECTION 813. Waiver of Past Defaults. | 45 | |||
SECTION 814. Undertaking for Costs. | 45 | |||
SECTION 815. Waiver of Stay or Extension Laws. | 46 | |||
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ARTICLE NINE The Trustee | 46 | |||
SECTION 901. Certain Duties and Responsibilities. | 46 | |||
SECTION 902. Notice of Defaults. | 47 | |||
SECTION 903. Certain Rights of Trustee. | 47 | |||
SECTION 904. Not Responsible for Recitals or Issuance of Securities. | 48 | |||
SECTION 905. May Hold Securities. | 48 | |||
SECTION 906. Money Held in Trust. | 49 | |||
SECTION 907. Compensation and Reimbursement. | 49 | |||
SECTION 908. Disqualification; Conflicting Interests. | 50 | |||
SECTION 909. Corporate Trustee Required; Eligibility. | 51 | |||
SECTION 910. Resignation and Removal; Appointment of Successor. | 51 | |||
SECTION 911. Acceptance of Appointment by Successor. | 53 | |||
SECTION 912. Merger, Conversion, Consolidation or Succession to Business. | 54 | |||
SECTION 913. Preferential Collection of Claims Against Company. | 54 | |||
SECTION 914. Co-trustees and Separate Trustees. | 55 | |||
SECTION 915. Appointment of Authenticating Agent. | 56 | |||
ARTICLE TEN Holders’ Lists and Reports by Trustee and Company | 58 | |||
SECTION 1001. Lists of Holders. | 58 | |||
SECTION 1002. Reports by Trustee and Company. | 58 | |||
ARTICLE ELEVEN Consolidation, Merger, Conveyance or Other Transfer | 58 | |||
SECTION 1101. Company May Consolidate, etc., Only on Certain Terms. | 58 | |||
SECTION 1102. Successor Corporation Substituted. | 59 | |||
SECTION 1103. Limitations. | 59 | |||
ARTICLE TWELVE Supplemental Indentures | 60 | |||
SECTION 1201. Supplemental Indentures Without Consent of Holders. | 60 | |||
SECTION 1202. Supplemental Indentures With Consent of Holders. | 62 | |||
SECTION 1203. Execution of Supplemental Indentures. | 63 | |||
SECTION 1204. Effect of Supplemental Indentures. | 63 | |||
SECTION 1205. Conformity With Trust Indenture Act. | 64 | |||
SECTION 1206. Reference in Securities to Supplemental Indentures. | 64 | |||
SECTION 1207. Modification Without Supplemental Indenture. | 64 | |||
ARTICLE THIRTEEN Meetings of Holders; Action Without Meeting | 64 | |||
SECTION 1301. Purposes for Which Meetings May Be Called. | 64 | |||
SECTION 1302. Call, Notice and Place of Meetings. | 64 | |||
SECTION 1303. Persons Entitled to Vote at Meetings. | 65 | |||
SECTION 1304. Quorum; Action. | 65 | |||
SECTION 1305. Attendance at Meetings; Determination of Voting Rights; | 66 | |||
SECTION 1306. Counting Votes and Recording Action of Meetings. | 67 | |||
SECTION 1307. Action Without Meeting. | 68 | |||
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ARTICLE FOURTEEN Immunity of Incorporators, Shareholders, Members, Officers, Managers and Directors | 68 | |||
SECTION 1401. Liability Solely Corporate. | 68 | |||
ARTICLE FIFTEEN Series Q Notes | 68 | |||
SECTION 1501. Designation of Series Q Notes. | 68 | |||
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TXU CORP.
Reconciliation and tie between Trust Indenture Act of 1939
and Indenture, dated as of November 1, 2004
| Trust Indenture Act Section | Indenture Section | |||
| §310 | (a)(1) | 909 | ||
| (a)(2) | 909 | |||
| (a)(3) | 914 | |||
| (a)(4) | Not Applicable | |||
| (b) | 908 | |||
| 910 | ||||
| §311 | (a) | 913 | ||
| (b) | 913 | |||
| (c) | 913 | |||
| §312 | (a) | 1001 | ||
| (b) | 1001 | |||
| (c) | 1001 | |||
| §313 | (a) | 1002 | ||
| (b) | 1002 | |||
| (c) | 1002 | |||
| §314 | (a) | 1002 | ||
| (a)(4) | 606 | |||
| (b) | Not Applicable | |||
| (c)(1) | 102 | |||
| (c)(2) | 102 | |||
| (c)(3) | Not Applicable | |||
| (d) | Not Applicable | |||
| (e) | 102 | |||
| §315 | (a) | 901 | ||
| 903 | ||||
| (b) | 902 | |||
| (c) | 901 | |||
| (d) | 901 | |||
| (e) | 814 | |||
| §316 | (a) | 812 | ||
| 813 | ||||
| (a)(1)(A) | 802 | |||
| 812 | ||||
| (a)(1)(B) | 813 | |||
| (a)(2) | Not Applicable | |||
| (b) | 808 | |||
| §317 | (a)(1) | 803 | ||
| (a)(2) | 804 | |||
| (b) | 603 | |||
| §318 | (a) | 107 | ||
Table of Contents
INDENTURE, dated as of November 1, 2004, betweenTXU CORP., a corporation duly organized and existing under the laws of the State of Texas (herein called the “Company”), having its principal office at Energy Plaza, 1601 Bryan Street, Dallas, Texas 75201, andTHE BANK OF NEW YORK, a New York banking corporation, having its principal corporate trust office at 101 Barclay Street, New York, New York 10286, as Trustee (herein called the “Trustee”).
RECITAL OF THE COMPANY
The Company has duly authorized the execution and delivery of this Indenture to provide for the issuance from time to time of its unsecured debentures, notes or other evidences of indebtedness (herein called the “Securities”), in an unlimited aggregate principal amount to be issued in one or more series as contemplated herein; and all acts necessary to make this Indenture a valid agreement of the Company have been performed.
For all purposes of this Indenture, except as otherwise expressly provided herein or unless the context otherwise requires, capitalized terms used herein shall have the meanings assigned to them in Article One of this Indenture.
NOW, THEREFORE, THIS INDENTURE WITNESSETH:
For and in consideration of the premises and the purchase of the Securities by the Holders thereof, it is mutually covenanted and agreed, for the equal and proportionate benefit of all Holders of the Securities or of any series thereof, as follows:
ARTICLE ONE
Definitions and Other Provisions of General Application
SECTION 101. Definitions.
For all purposes of this Indenture, except as otherwise expressly provided or unless the context otherwise requires:
(a) the terms defined in this Article have the meanings assigned to them in this Article and include the plural as well as the singular;
(b) all terms used herein without definition which are defined in the Trust Indenture Act, either directly or by reference therein, have the meanings assigned to them therein;
(c) all accounting terms not otherwise defined herein have the meanings assigned to them in accordance with generally accepted accounting principles in the United States, and, except as otherwise herein expressly provided, the term “generally accepted accounting principles” with respect to any computation required or permitted hereunder shall mean such accounting principles as are generally accepted in the United States at the date of such computation or, at the election of the Company from time to time, at the date of the execution and delivery of this Indenture; provided, however, that in determining generally accepted accounting principles applicable to the Company, the Company shall, to the extent required, conform to any order, rule or regulation of any administrative agency, regulatory authority or other governmental body having jurisdiction over the Company;
Table of Contents
(d) any reference to an “Article” or a “Section” refers to an Article or a Section, as the case may be, of this Indenture; and
(e) the words “herein”, “hereof” and “hereunder” and other words of similar import refer to this Indenture as a whole and not to any particular Article, Section or other subdivision.
Certain terms, used principally in Article Nine, are defined in that Article.
“Act”, when used with respect to any Holder of a Security, has the meaning specified in Section 104.
“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, “control” when used with respect to any specified Person means the power to direct the management and policies of such Person, directly or through one or more intermediaries, whether through the ownership of voting securities, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing.
“Authenticating Agent” means any Person (other than the Company or an Affiliate of the Company) authorized by the Trustee pursuant to Section 915 to act on behalf of the Trustee to authenticate one or more series of Securities or Tranche thereof.
“Authorized Officer” means the Chairman of the Board, the Vice Chairman, the President, any Vice President, the Treasurer, any Assistant Treasurer, or any other officer or agent of the Company duly authorized by the Board of Directors to act in respect of matters relating to this Indenture.
“Board of Directors” means either the board of directors of the Company or any committee thereof duly authorized to act in respect of matters relating to this Indenture.
“Board Resolution” means a copy of a resolution certified by the Secretary or an Assistant Secretary of the Company to have been duly adopted by the Board of Directors and to be in full force and effect on the date of such certification, and delivered to the Trustee.
“Business Day”, when used with respect to a Place of Payment or any other particular location specified in the Securities or this Indenture, means any day, other than a Saturday or Sunday, which is not a day on which banking institutions or trust companies in such Place of Payment or other location are generally authorized or required by law, regulation or executive order to remain closed, except as may be otherwise specified as contemplated by Section 301.
“Commission” means the Securities and Exchange Commission, as from time to time constituted, created under the Securities Exchange Act of 1934, as amended, or, if at any
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time after the date of execution and delivery of this Indenture such Commission is not existing and performing the duties now assigned to it under the Trust Indenture Act, then the body, if any, performing such duties at such time.
“Company” means the Person named as the “Company” in the first paragraph of this Indenture until a successor Person shall have become such pursuant to the applicable provisions of this Indenture, and thereafter “Company” shall mean such successor Person.
“Company Request” or “Company Order” means a written request or order signed in the name of the Company by an Authorized Officer and delivered to the Trustee.
“Corporate Trust Office” means the office of the Trustee at which at any particular time its corporate trust business shall be principally administered, which office at the date of execution and delivery of this Indenture is located at 101 Barclay Street, Floor 8 W, New York, New York 10286.
“corporation” means a corporation, association, company, limited liability company, partnership, joint stock company, business or statutory trust or other business entity, and references to “corporate” and other derivations of “corporation” herein shall be deemed to include appropriate derivations of such entities.
“Defaulted Interest” has the meaning specified in Section 307.
“Discount Security” means any Security which provides for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration of the Maturity thereof pursuant to Section 802. “Interest” with respect to a Discount Security means interest, if any, borne by such Security at a Stated Interest Rate.
“Dollar” or “$” means a dollar or other equivalent unit in such coin or currency of the United States as at the time shall be legal tender for the payment of public and private debts.
“Eligible Obligations” means:
(a) with respect to Securities denominated in Dollars, Government Obligations; or
(b) with respect to Securities denominated in a currency other than Dollars or in a composite currency, such other obligations or instruments as shall be specified with respect to such Securities, as contemplated by Section 301.
“Event of Default” has the meaning specified in Section 801.
“Governmental Authority” means the government of the United States or of any State or territory thereof or of the District of Columbia or of any county, municipality or other political subdivision of any of the foregoing, or any department, agency, authority or other instrumentality of any of the foregoing.
“Government Obligations” means:
(a) direct obligations of, or obligations the principal of and interest on which are unconditionally guaranteed by, the United States and entitled to the benefit of the full faith and credit thereof; and
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(b) certificates, depositary receipts or other instruments which evidence a direct ownership interest in obligations described in clause (a) above or in any specific interest or principal payments due in respect thereof; provided, however, that the custodian of such obligations or specific interest or principal payments shall be a bank or trust company (which may include the Trustee or any Paying Agent) subject to Federal or state supervision or examination with a combined capital and surplus of at least $50,000,000; and provided, further, that except as may be otherwise required by law, such custodian shall be obligated to pay to the holders of such certificates, depositary receipts or other instruments the full amount received by such custodian in respect of such obligations or specific payments and shall not be permitted to make any deduction therefrom.
“Holder” means a Person in whose name a Security is registered in the Security Register.
“Indenture” means this instrument as originally executed and delivered and as it may from time to time be supplemented or amended by one or more indentures supplemental hereto entered into pursuant to the applicable provisions hereof, including, for all purposes of this instrument and any such supplemental indenture, the provisions of the Trust Indenture Act that are deemed to be a part of and govern this Indenture and any such supplemental indenture, respectively. The term “Indenture” shall also include the provisions or terms of particular series of Securities established as contemplated by Section 301.
“Interest Payment Date”, when used with respect to any Security, means the Stated Maturity of an installment of interest on such Security.
“Maturity”, when used with respect to any Security, means the date on which the principal of such Security or an installment of principal becomes due and payable as provided in such Security or in this Indenture, whether at the Stated Maturity, by declaration of acceleration, upon call for redemption or otherwise.
“Officer’s Certificate” means a certificate signed by an Authorized Officer and delivered to the Trustee.
“Opinion of Counsel” means a written opinion of counsel, who may be counsel for the Company, or other counsel reasonably acceptable to the Trustee.
“Outstanding”, when used with respect to Securities, means, as of the date of determination, all Securities theretofore authenticated and delivered under this Indenture, except:
(a) Securities theretofore canceled or delivered to the Security Registrar for cancellation;
(b) Securities deemed to have been paid in accordance with Section 701; and
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(c) Securities which have been paid pursuant to Section 306 or in exchange for or in lieu of which other Securities have been authenticated and delivered pursuant to this Indenture, other than any such Securities in respect of which there shall have been presented to the Trustee proof satisfactory to it and the Company that such Securities are held by a bona fide purchaser or purchasers in whose hands such Securities are valid obligations of the Company;
provided, however, that in determining whether or not the Holders of the requisite principal amount of the Securities Outstanding under this Indenture, or the Outstanding Securities of any series or Tranche, have given any request, demand, authorization, direction, notice, consent or waiver hereunder or whether or not a quorum is present at a meeting of Holders of Securities,
(x) Securities owned by the Company or any other obligor upon the Securities or any Affiliate of the Company or of such other obligor (unless the Company, such Affiliate or such obligor owns all Securities Outstanding under this Indenture, or (except for the purposes of actions to be taken by Holders of (i) more than one series voting as a class under Section 812 or (ii) more than one series or more than one Tranche, as the case may be, voting as a class under Section 1202) all Outstanding Securities of each such series and each such Tranche, as the case may be, determined without regard to this clause (x)) shall be disregarded and deemed not to be Outstanding, except that, in determining whether the Trustee shall be protected in relying upon any such request, demand, authorization, direction, notice, consent or waiver or upon any such determination as to the presence of a quorum, only Securities which a Responsible Officer of the Trustee actually knows to be so owned shall be so disregarded; provided, however, that Securities so owned which have been pledged in good faith may be regarded as Outstanding if the pledgee establishes to the satisfaction of the Trustee the pledgee’s right so to act with respect to such Securities and that the pledgee is not the Company or any other obligor upon the Securities or any Affiliate of the Company or of such other obligor; and
(y) the principal amount of a Discount Security that shall be deemed to be Outstanding for such purposes shall be the amount of the principal thereof that would be due and payable as of the date of such determination upon a declaration of acceleration of the Maturity thereof pursuant to Section 802;
provided, further, that, in the case of any Security the principal of which is payable from time to time without presentment or surrender, the principal amount of such Security that shall be deemed to be Outstanding at any time for all purposes of this Indenture shall be the original principal amount thereof less the aggregate amount of principal thereof theretofore paid.
“Paying Agent” means any Person, including the Company, authorized by the Company to pay the principal of, and premium, if any, or interest, if any, on any Securities on behalf of the Company.
“Periodic Offering” means an offering of Securities of a series from time to time any or all of the specific terms of which Securities, including without limitation the rate or rates
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of interest, if any, thereon, the Stated Maturity or Maturities thereof and the redemption provisions, if any, with respect thereto, are to be determined by the Company or its agents from time to time subsequent to the initial request for the authentication and delivery of such Securities by the Trustee, as contemplated in Section 301 and clause (b) of Section 303.
“Person” means any individual, corporation, joint venture, trust or unincorporated organization or any Governmental Authority.
“Place of Payment”, when used with respect to the Securities of any series, or any Tranche thereof, means the place or places, specified as contemplated by Section 301, at which, subject to Section 602, principal of and premium, if any, and interest, if any, on the Securities of such series or Tranche are payable.
“Predecessor Security” of any particular Security means every previous Security evidencing all or a portion of the same debt as that evidenced by such particular Security; and, for the purposes of this definition, any Security authenticated and delivered under Section 306 in exchange for or in lieu of a mutilated, destroyed, lost or stolen Security shall be deemed (to the extent lawful) to evidence the same debt as the mutilated, destroyed, lost or stolen Security.
“Redemption Date”, when used with respect to any Security to be redeemed, means the date fixed for such redemption by or pursuant to this Indenture.
“Redemption Price”, when used with respect to any Security to be redeemed, means the price at which it is to be redeemed pursuant to this Indenture, exclusive of accrued and unpaid interest.
“Regular Record Date” for the interest payable on any Interest Payment Date on the Securities of any series means the date specified for that purpose as contemplated by Section 301.
“Required Currency” has the meaning specified in Section 311.
“Responsible Officer”, when used with respect to the Trustee, means any Vice President, Assistant Vice President, Trust Officer or other officer of the Trustee who, in the case of each of the foregoing, is assigned by the Trustee to its corporate trust department responsible for the administration of this Indenture that is located in the Corporate Trust Office.
“Securities” has the meaning stated in the first recital of this Indenture and more particularly means any securities authenticated and delivered under this Indenture.
“Security Register” and “Security Registrar” have the respective meanings specified in Section 305.
“Special Record Date” for the payment of any Defaulted Interest on the Securities of any series means a date fixed by the Trustee pursuant to Section 307.
“Stated Interest Rate” means a rate (whether fixed or variable) at which an obligation by its terms is stated to bear simple interest. Any calculation or other determination to
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be made under this Indenture by reference to the Stated Interest Rate on a Security shall be made without regard to the effective interest cost to the Company of such Security and without regard to the Stated Interest Rate on, or the effective cost to the Company of, any other indebtedness in respect of which the Company’s obligations are evidenced or secured in whole or in part by such Security.
“Stated Maturity”, when used with respect to any obligation or any installment of principal thereof or interest thereon, means the date on which the principal of such obligation or such installment of principal or interest is stated to be due and payable (without regard to any provisions for redemption, prepayment, acceleration, purchase or extension).
“Subsidiary” means a corporation more than 50% of the outstanding voting stock of which is owned, directly or indirectly, by the Company or by one or more other Subsidiaries, or by the Company and one or more other Subsidiaries. For the purposes of this definition, “voting stock” means stock (or other interests) of a corporation having voting power for the election of directors, managers or trustees thereof, whether at all times or only so long as no senior class of stock (or other interests) has such voting power by reason of any contingency.
“Tranche” means a group of Securities which (a) are of the same series and (b) have identical terms except as to principal amount and/or date of issuance.
“Trust Indenture Act” means, as of any time, the Trust Indenture Act of 1939, or any successor statute, as in effect at such time.
“Trustee” means the Person named as the “Trustee” in the first paragraph of this Indenture until a successor Trustee shall have become such with respect to one or more series of Securities pursuant to the applicable provisions of this Indenture, and thereafter “Trustee” shall mean or include each Person who is then a Trustee hereunder, and if at any time there is more than one such Person, “Trustee” as used with respect to the Securities of any series shall mean the Trustee with respect to Securities of that series.
“United States” means the United States of America, its territories, its possessions and other areas subject to its political jurisdiction.
SECTION 102. Compliance Certificates and Opinions.
Except as otherwise expressly provided in this Indenture, upon any application or request by the Company to the Trustee to take any action under any provision of this Indenture, the Company shall, if requested by the Trustee, furnish to the Trustee an Officer’s Certificate stating that in the opinion of the Authorized Officer executing such Officer’s Certificate all conditions precedent, if any, provided for in this Indenture relating to the proposed action (including any covenants compliance with which constitutes a condition precedent) have been complied with and an Opinion of Counsel stating that in the opinion of such counsel all such conditions precedent, if any, have been complied with, except that in the case of any such application or request as to which the furnishing of such documents is specifically required by any provision of this Indenture relating to such particular application or request, no additional certificate or opinion need be furnished.
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Every certificate or opinion with respect to compliance with a condition or covenant provided for in this Indenture shall include:
(a) a statement that each Person signing such certificate or opinion has read such covenant or condition and the definitions herein relating thereto;
(b) a brief statement as to the nature and scope of the examination or investigation upon which the statements or opinions contained in such certificate or opinion are based;
(c) a statement that, in the opinion of each such Person, such Person has made such examination or investigation as is necessary to enable such Person to express an informed opinion as to whether or not such covenant or condition has been complied with; and
(d) a statement as to whether, in the opinion of each such Person, such condition or covenant has been complied with.
SECTION 103. Form of Documents Delivered to Trustee.
In any case where several matters are required to be certified by, or covered by an opinion of, any specified Person, it is not necessary that all such matters be certified by, or covered by the opinion of, only one such Person, or that they be so certified or covered by only one document, but one such Person may certify or give an opinion with respect to some matters and one or more other such Persons as to other matters, and any such Person may certify or give an opinion as to such matters in one or several documents.
Any certificate or opinion of an officer of the Company may be based, insofar as it relates to legal matters, upon a certificate or opinion of, or representations by, counsel, unless such officer knows, or in the exercise of reasonable care should know, that the certificate or opinion or representations with respect to the matters upon which such officer’s certificate or opinion are based are erroneous. Any such certificate or Opinion of Counsel may be based, insofar as it relates to factual matters, upon a certificate or opinion of, or representations by, an officer or officers of the Company stating that the information with respect to such factual matters is in the possession of the Company, unless such counsel knows, or in the exercise of reasonable care should know, that the certificate or opinion or representations with respect to such matters are erroneous.
Where any Person is required to make, give or execute two or more applications, requests, consents, certificates, statements, opinions or other instruments under this Indenture, they may, but need not, be consolidated and form one instrument.
Whenever, subsequent to the receipt by the Trustee of any Board Resolution, Officer’s Certificate, Opinion of Counsel or other document or instrument, a clerical, typographical or other inadvertent or unintentional error or omission shall be discovered therein, a new document or instrument may be substituted therefor in corrected form with the same force and effect as if originally filed in the corrected form and, irrespective of the date or dates of the actual execution and/or delivery thereof, such substitute document or instrument shall be deemed to have been executed and/or delivered as of the date or dates required with respect to the document or instrument for which it is substituted. Anything in this Indenture to the contrary
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notwithstanding, if any such corrective document or instrument indicates that action has been taken by or at the request of the Company which could not have been taken had the original document or instrument not contained such error or omission, the action so taken shall not be invalidated or otherwise rendered ineffective but shall be and remain in full force and effect, except to the extent that such action was a result of willful misconduct or bad faith. Without limiting the generality of the foregoing, any Securities issued under the authority of such defective document or instrument shall nevertheless be the valid obligations of the Company entitled to the benefits of this Indenture equally and ratably with all other Outstanding Securities, except as aforesaid.
SECTION 104. Acts of Holders.
(a) Any request, demand, authorization, direction, notice, consent, election, waiver or other action provided by this Indenture to be made, given or taken by Holders may be embodied in and evidenced by one or more instruments of substantially similar tenor signed by such Holders in person or by an agent duly appointed in writing or, alternatively, may be embodied in and evidenced by the record of Holders voting in favor thereof, either in person or by proxies duly appointed in writing, at any meeting of Holders duly called and held in accordance with the provisions of Article Thirteen, or a combination of such instruments and any such record. Except as herein otherwise expressly provided, such action shall become effective when such instrument or instruments or record or both are delivered to the Trustee and, where it is hereby expressly required, to the Company. Such instrument or instruments and any such record (and the action embodied therein and evidenced thereby) are herein sometimes referred to as the “Act” of the Holders signing such instrument or instruments and so voting at any such meeting. Proof of execution of any such instrument or of a writing appointing any such agent, or of the holding by any Person of a Security, shall be sufficient for any purpose of this Indenture and (subject to Section 901) conclusive in favor of the Trustee and the Company, if made in the manner provided in this Section. The record of any meeting of Holders shall be proved in the manner provided in Section 1306.
(b) The fact and date of the execution by any Person of any such instrument or writing may be proved by the affidavit of a witness of such execution or by a certificate of a notary public or other officer authorized by law to take acknowledgments of deeds, certifying that the individual signing such instrument or writing acknowledged to him the execution thereof or may be proved in any other manner which the Trustee and the Company deem sufficient. Where such execution is by a signer acting in a capacity other than his individual capacity, such certificate or affidavit shall also constitute sufficient proof of his authority.
(c) The ownership, principal amount (except as otherwise contemplated in clause (y) of the first proviso to the definition of Outstanding) and serial numbers of Securities held by any Person, and the date of holding the same, shall be proved by the Security Register.
(d) Any request, demand, authorization, direction, notice, consent, election, waiver or other Act of a Holder shall bind every future Holder of the same Security and the Holder of every Security issued upon the registration of transfer thereof or in exchange therefor or in
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lieu thereof in respect of anything done, omitted or suffered to be done by the Trustee or the Company in reliance thereon, whether or not notation of such action is made upon such Security.
(e) Until such time as written instruments shall have been delivered to the Trustee with respect to the requisite percentage of principal amount of Securities for the action contemplated by such instruments, any such instrument executed and delivered by or on behalf of a Holder may be revoked with respect to any or all of such Securities by written notice by such Holder or any subsequent Holder, proven in the manner in which such instrument was proven.
(f) Securities of any series, or any Tranche thereof, authenticated and delivered after any Act of Holders may, and shall if required by the Trustee, bear a notation in form approved by the Trustee as to any action taken by such Act of Holders. If the Company shall so determine, new Securities of any series, or any Tranche thereof, so modified as to conform, in the opinion of the Trustee and the Company, to such action may be prepared and executed by the Company and authenticated and delivered by the Trustee in exchange for Outstanding Securities of such series or Tranche.
(g) If the Company shall solicit from Holders any request, demand, authorization, direction, notice, consent, waiver or other Act, the Company may, at its option, fix in advance a record date for the determination of Holders entitled to give such request, demand, authorization, direction, notice, consent, waiver or other Act, but the Company shall have no obligation to do so. If such a record date is fixed, such request, demand, authorization, direction, notice, consent, waiver or other Act may be given before or after such record date, but only the Holders of record at the close of business on the record date shall be deemed to be Holders for the purposes of determining whether Holders of the requisite proportion of the Outstanding Securities have authorized or agreed or consented to such request, demand, authorization, direction, notice, consent, waiver or other Act, and for that purpose the Outstanding Securities shall be computed as of the record date.
SECTION 105. Notices, etc. to Trustee and Company.
Any request, demand, authorization, direction, notice, consent, election, waiver or Act of Holders or other document provided or permitted by this Indenture to be made upon, given or furnished to, or filed with, the Trustee by any Holder or by the Company, or the Company by the Trustee or by any Holder, shall be sufficient for every purpose hereunder (unless otherwise herein expressly provided) if in writing and delivered personally to an officer or other responsible employee of the addressee at the applicable location set forth below or at such other location as such party may from time to time designate by written notice, or transmitted by facsimile transmission or other direct written electronic means to such telephone number or other electronic communications address as the parties hereto shall from time to time designate by written notice, or transmitted by certified or registered mail, charges prepaid, to the applicable address set forth below or to such other address as either party hereto may from time to time designate by written notice:
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| If to the Trustee, to: | ||||
The Bank of New York Corporate Trust Division, Corporate Finance Unit 101 Barclay Street, Floor 8W New York, New York 10286 | ||||
| Attention: | Remo J. Reale | |||
| Telephone: | (212) 815-2492 | |||
| Telecopy: | (212) 815-5707 | |||
| If to the Company, to: | ||||
TXU Corp. Energy Plaza 1601 Bryan Street Dallas, Texas 75201 | ||||
| Attention: | Treasurer | |||
| Telephone: | (214) 812-5565 | |||
| Telecopy: | (214) 812-8998 | |||
Any communication contemplated herein shall be deemed to have been made, given, furnished and filed if personally delivered, on the date of delivery, if transmitted by facsimile transmission or other direct written electronic means, on the date of receipt, and if transmitted by certified or registered mail, on the date of receipt.
SECTION 106. Notice to Holders of Securities; Waiver.
Except as otherwise expressly provided herein, where this Indenture provides for notice to Holders of any event, such notice shall be sufficiently given, and shall be deemed given, to Holders if in writing and mailed, first-class postage prepaid, to each Holder affected by such event, at the address of such Holder as it appears in the Security Register, not later than the latest date, if any, and not earlier than the earliest date, if any, prescribed for the giving of such notice.
In case by reason of the suspension of regular mail service or by reason of any other cause it shall be impracticable to give such notice to Holders by mail, then such notification as shall be made with the approval of the Trustee shall constitute a sufficient notification for every purpose hereunder. In any case where notice to Holders is given by mail, neither the failure to mail such notice, nor any defect in any notice so mailed, to any particular Holder shall affect the sufficiency of such notice with respect to other Holders.
Any notice required by this Indenture may be waived in writing by the Person entitled to receive such notice, either before or after the event otherwise to be specified therein, and such waiver shall be the equivalent of such notice. Waivers of notice by Holders shall be filed with the Trustee, but such filing shall not be a condition precedent to the validity of any action taken in reliance upon such waiver.
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SECTION 107. Conflict with Trust Indenture Act.
In the event this Indenture becomes subject to the Trust Indenture Act, (a) if any provision of this Indenture limits, qualifies or conflicts with another provision hereof which is required or deemed to be included in this Indenture by, or is otherwise governed by, any of the provisions of the Trust Indenture Act, such other provision shall control; and (b) if any provision hereof otherwise conflicts with the Trust Indenture Act, the Trust Indenture Act shall control unless otherwise provided as contemplated by Section 301 with respect to any series of Securities.
SECTION 108. Effect of Headings and Table of Contents.
The Article and Section headings in this Indenture and the Table of Contents are for convenience only and shall not affect the construction hereof.
SECTION 109. Successors and Assigns.
All covenants and agreements in this Indenture by the Company and Trustee shall bind their respective successors and assigns, whether so expressed or not.
SECTION 110. Separability Clause.
In case any provision in this Indenture or the Securities shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.
SECTION 111. Benefits of Indenture.
Nothing in this Indenture or the Securities, express or implied, shall give to any Person, other than the parties hereto, their successors hereunder and the Holders, any benefit or any legal or equitable right, remedy or claim under this Indenture.
SECTION 112. Governing Law.
This Indenture and the Securities shall be governed by and construed in accordance with the law of the State of New York (including, without limitation, Section 5-1401 of the New York General Obligations Law or any successor to such statute), except to the extent that the Trust Indenture Act shall be applicable.
SECTION 113. Legal Holidays.
In any case where any Interest Payment Date, Redemption Date or Stated Maturity of any Security shall not be a Business Day at any Place of Payment, then (notwithstanding any other provision of this Indenture or of the Securities other than a provision in Securities of any series, or any Tranche thereof, or in the indenture supplemental hereto, Board Resolution or Officer’s Certificate which establishes the terms of the Securities of such series or Tranche, which specifically states that such provision shall apply in lieu of this Section) payment of interest or principal and premium, if any, need not be made at such Place of Payment
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on such date, but may be made on the next succeeding Business Day at such Place of Payment, with the same force and effect, and in the same amount, as if made on the Interest Payment Date or Redemption Date, or at the Stated Maturity, as the case may be, and, if such payment is made or duly provided for on such Business Day, no interest shall accrue on the amount so payable for the period from and after such Interest Payment Date, Redemption Date or Stated Maturity, as the case may be, to such Business Day.
ARTICLE TWO
Security Forms
SECTION 201. Forms Generally.
The definitive Securities of each series shall be in substantially the form or forms thereof established in the indenture supplemental hereto establishing such series or in a Board Resolution establishing such series, or in an Officer’s Certificate pursuant to such supplemental indenture or Board Resolution, in each case with such appropriate insertions, omissions, substitutions and other variations as are required or permitted by this Indenture, and may have such letters, numbers or other marks of identification and such legends or endorsements placed thereon as may be required to comply with the rules of any securities exchange or as may, consistently herewith, be determined by the officers executing such Securities, as evidenced by their execution thereof. If the form or forms of Securities of any series are established in a Board Resolution or in an Officer’s Certificate pursuant to a supplemental indenture or a Board Resolution, such Board Resolution and Officer’s Certificate, if any, shall be delivered to the Trustee at or prior to the delivery of the Company Order contemplated by Section 303 for the authentication and delivery of such Securities.
Unless otherwise specified as contemplated by Section 301 or clause (g) of Section 1201, the Securities of each series shall be issuable in registered form without coupons. The definitive Securities shall be produced in such manner as shall be determined by the officers executing such Securities, as evidenced by their execution thereof.
SECTION 202. Form of Trustee’s Certificate of Authentication.
The Trustee’s certificate of authentication shall be in substantially the form set forth below:
This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.
Dated:
| ||
| as Trustee | ||
| By: |
| |
| Authorized Signatory | ||
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ARTICLE THREE
The Securities
SECTION 301. Amount Unlimited; Issuable in Series.
The aggregate principal amount of Securities which may be authenticated and delivered under this Indenture is unlimited.
The Securities may be issued in one or more series. Subject to the last paragraph of this Section, prior to the authentication and delivery of Securities of any series there shall be established by specification in a supplemental indenture or in a Board Resolution, or in an Officer’s Certificate pursuant to a supplemental indenture or a Board Resolution:
(a) the title of the Securities of such series (which shall distinguish the Securities of such series from Securities of all other series);
(b) any limit upon the aggregate principal amount of the Securities of such series which may be authenticated and delivered under this Indenture (except for Securities authenticated and delivered upon registration of transfer of, or in exchange for, or in lieu of, other Securities of such series pursuant to Section 304, 305, 306, 406 or 1206 and except for any Securities which, pursuant to Section 303, are deemed never to have been authenticated and delivered hereunder);
(c) the Person or Persons (without specific identification) to whom interest on Securities of such series, or any Tranche thereof, shall be payable on any Interest Payment Date, if other than the Persons in whose names such Securities (or one or more Predecessor Securities) are registered at the close of business on the Regular Record Date for such interest;
(d) the date or dates on which the principal of the Securities of such series, or any Tranche thereof, is payable or any formulary or other method or other means by which such date or dates shall be determined, by reference to an index or other fact or event ascertainable outside of this Indenture or otherwise (without regard to any provisions for redemption, prepayment, acceleration, purchase or extension);
(e) the rate or rates at which the Securities of such series, or any Tranche thereof, shall bear interest, if any (including the rate or rates at which overdue principal shall bear interest, if different from the rate or rates at which such Securities shall bear interest prior to Maturity, and, if applicable, the rate or rates at which overdue premium or interest shall bear interest, if any), or any formulary or other method or other means by which such rate or rates shall be determined, by reference to an index or other fact or event ascertainable outside of this Indenture or otherwise; the date or dates from which such interest shall accrue; the Interest Payment Dates on which such interest shall be payable and the Regular Record Date, if any, for the interest payable on such Securities on any Interest Payment Date; the right of the Company, if any, to extend the interest payment periods and the duration of any such extension as contemplated by Section 312; and the basis of computation of interest, if other than as provided in Section 310;
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(f) the place or places at which or methods by which (1) the principal of and premium, if any, and interest, if any, on Securities of such series, or any Tranche thereof, shall be payable, (2) registration of transfer of Securities of such series, or any Tranche thereof, may be effected, (3) exchanges of Securities of such series, or any Tranche thereof, may be effected and (4) notices and demands to or upon the Company in respect of the Securities of such series, or any Tranche thereof, and this Indenture may be served; the Security Registrar and any Paying Agent or Agents for such series or Tranche; and if such is the case, that the principal of such Securities shall be payable without presentment or surrender thereof;
(g) the period or periods within which, or the date or dates on which, the price or prices at which and the terms and conditions upon which the Securities of such series, or any Tranche thereof, may be redeemed, in whole or in part, at the option of the Company and any restrictions on such redemptions, including but not limited to a restriction on a partial redemption by the Company of the Securities of any series, or any Tranche thereof, resulting in delisting of such Securities from any national exchange;
(h) the obligation or obligations, if any, of the Company to redeem or purchase the Securities of such series, or any Tranche thereof, pursuant to any sinking fund or other mandatory redemption provisions or at the option of a Holder thereof and the period or periods within which or the date or dates on which, the price or prices at which and the terms and conditions upon which such Securities shall be redeemed or purchased, in whole or in part, pursuant to such obligation, and applicable exceptions to the requirements of Section 404 in the case of mandatory redemption or redemption at the option of the Holder;
(i) the denominations in which Securities of such series, or any Tranche thereof, shall be issuable if other than denominations of $1,000 and any integral multiple thereof;
(j) the currency or currencies, including composite currencies, in which payment of the principal of and premium, if any, and interest, if any, on the Securities of such series, or any Tranche thereof, shall be payable (if other than in Dollars);
(k) if the principal of or premium, if any, or interest, if any, on the Securities of such series, or any Tranche thereof, are to be payable, at the election of the Company or a Holder thereof, in a coin or currency other than that in which the Securities are stated to be payable, the period or periods within which and the terms and conditions upon which, such election may be made;
(l) if the principal of or premium, if any, or interest, if any, on the Securities of such series, or any Tranche thereof, are to be payable, or are to be payable at the election of the Company or a Holder thereof, in securities or other property, the type and amount of such securities or other property, or the formulary or other method or other means by which such amount shall be determined, and the period or periods within which, and the terms and conditions upon which, any such election may be made;
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(m) if the amount payable in respect of principal of or premium, if any, or interest, if any, on the Securities of such series, or any Tranche thereof, may be determined with reference to an index or other fact or event ascertainable outside of this Indenture, the manner in which such amounts shall be determined to the extent not established pursuant to clause (e) of this paragraph;
(n) if other than the principal amount thereof, the portion of the principal amount of Securities of such series, or any Tranche thereof, which shall be payable upon declaration of acceleration of the Maturity thereof pursuant to Section 802;
(o) any Events of Default, in addition to those specified in Section 801, with respect to the Securities of such series, and any covenants of the Company for the benefit of the Holders of the Securities of such series, or any Tranche thereof, in addition to those set forth in Article Six;
(p) the terms, if any, pursuant to which the Securities of such series, or any Tranche thereof, may be converted into or exchanged for shares of capital stock or other securities of the Company or any other Person;
(q) the obligations or instruments, if any, which shall be considered to be Eligible Obligations in respect of the Securities of such series, or any Tranche thereof, denominated in a currency other than Dollars or in a composite currency, and any additional or alternative provisions for the reinstatement of the Company’s indebtedness in respect of such Securities after the satisfaction and discharge thereof as provided in Section 701;
(r) if the Securities of such series, or any Tranche thereof, are to be issued in global form, (i) any limitations on the rights of the Holder or Holders of such Securities to transfer or exchange the same or to obtain the registration of transfer thereof, (ii) any limitations on the rights of the Holder or Holders thereof to obtain certificates therefor in definitive form in lieu of temporary form and (iii) any and all other matters incidental to such Securities;
(s) if the Securities of such series, or any Tranche thereof, are to be issuable as bearer securities, any and all matters incidental thereto which are not specifically addressed in a supplemental indenture as contemplated by clause (g) of Section 1201;
(t) to the extent not established pursuant to clause (r) of this paragraph, any limitations on the rights of the Holders of the Securities of such Series, or any Tranche thereof, to transfer or exchange such Securities or to obtain the registration of transfer thereof; and if a service charge will be made for the registration of transfer or exchange of Securities of such series, or any Tranche thereof, the amount or terms thereof;
(u) any exceptions to Section 113, or variation in the definition of Business Day, with respect to the Securities of such series, or any Tranche thereof;
(v) any collateral security, assurance or guarantee for the Securities of such series;
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(w) any non-applicability of Section 608 to the Securities of such series or any exceptions or modifications of Section 608 with respect to the Securities of such series;
(x) any rights or duties of another Person to assume the obligations of the Company with respect to the Securities of such series (whether as joint obligor, primary obligor, secondary obligor or substitute obligor) and any rights or duties to discharge and release any obligor with respect to the Securities of such series or the Indenture to the extent related to such series; and
(y) any other terms of the Securities of such series, or any Tranche thereof, not inconsistent with the provisions of this Indenture.
With respect to Securities of a series subject to a Periodic Offering, the indenture supplemental hereto or the Board Resolution which establishes such series, or the Officer’s Certificate pursuant to such supplemental indenture or Board Resolution, as the case may be, may provide general terms or parameters for Securities of such series and provide either that the specific terms of Securities of such series, or any Tranche thereof, shall be specified in a Company Order or that such terms shall be determined by the Company or its agents in accordance with procedures specified in a Company Order as contemplated by clause (b) of Section 303.
Unless otherwise provided with respect to a series of Securities as contemplated in Section 301(b), the aggregate principal amount of a series of Securities may be increased and additional Securities of such series may be issued up to the maximum aggregate principal amount authorized with respect to such series as increased.
SECTION 302. Denominations.
Unless otherwise provided as contemplated by Section 301 with respect to any series of Securities, or any Tranche thereof, the Securities of each series shall be issuable in denominations of $1,000 and any integral multiple thereof.
SECTION 303. Execution, Authentication, Delivery and Dating.
Unless otherwise provided as contemplated by Section 301 with respect to any series of Securities, or any Tranche thereof, the Securities shall be executed on behalf of the Company by an Authorized Officer and may have the corporate seal of the Company affixed thereto or reproduced thereon attested by any other Authorized Officer or by the Secretary or an Assistant Secretary of the Company. The signature of any or all of these officers on the Securities may be manual or facsimile.
Securities bearing the manual or facsimile signatures of individuals who were at the time of execution Authorized Officers or the Secretary or an Assistant Secretary of the Company shall bind the Company, notwithstanding that such individuals or any of them have ceased to hold such offices prior to the authentication and delivery of such Securities or did not hold such offices at the date of such Securities.
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The Trustee shall authenticate and deliver Securities of a series, for original issue, at one time or from time to time in accordance with the Company Order referred to below, upon receipt by the Trustee of:
(a) the instrument or instruments establishing the form or forms and terms of such series, as provided in Sections 201 and 301;
(b) a Company Order requesting the authentication and delivery of such Securities and, to the extent that the terms of such Securities shall not have been established in an indenture supplemental hereto or in a Board Resolution, or in an Officer’s Certificate pursuant to a supplemental indenture or Board Resolution, all as contemplated by Sections 201 and 301, either (i) establishing such terms or (ii) in the case of Securities of a series subject to a Periodic Offering, specifying procedures, acceptable to the Trustee, by which such terms are to be established (which procedures may provide, to the extent acceptable to the Trustee, for authentication and delivery pursuant to oral or electronic instructions from the Company or any agent or agents thereof, which oral instructions are to be promptly confirmed electronically or in writing), in either case in accordance with the instrument or instruments delivered pursuant to clause (a) above;
(c) the Securities of such series, executed on behalf of the Company by an Authorized Officer;
(d) an Opinion of Counsel to the effect that:
| (i) | the form or forms of such Securities have been duly authorized by the Company and have been established in conformity with the provisions of this Indenture; |
| (ii) | the terms of such Securities have been duly authorized by the Company and have been established in conformity with the provisions of this Indenture; and |
| (iii) | when such Securities shall have been authenticated and delivered by the Trustee and issued and delivered by the Company in the manner and subject to any conditions specified in such Opinion of Counsel, such Securities will have been duly issued under this Indenture and will constitute valid and legally binding obligations of the Company, entitled to the benefits provided by this Indenture, and enforceable in accordance with their terms, subject, as to enforcement, to laws relating to or affecting generally the enforcement of mortgagees’ and other creditors’ rights, including, without limitation, bankruptcy, insolvency, reorganization, receivership, moratorium and other laws affecting the rights and remedies of creditors and mortgagees’ generally and general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law); |
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provided, however, that, with respect to Securities of a series subject to a Periodic Offering, the Trustee shall be entitled to receive such Opinion of Counsel only once at or prior to the time of the first authentication of such Securities (provided that such Opinion of Counsel addresses the authentication and delivery of all Securities of such series) and that in lieu of the opinions described in clauses (ii) and (iii) above Counsel may opine that:
(x) when the terms of such Securities shall have been established pursuant to a Company Order or Orders or pursuant to such procedures (acceptable to the Trustee) as may be specified from time to time by a Company Order or Orders, all as contemplated by and in accordance with the instrument or instruments delivered pursuant to clause (a) above, such terms will have been duly authorized by the Company and will have been established in conformity with the provisions of this Indenture; and
(y) such Securities, when (1) executed by the Company, (2) authenticated and delivered by the Trustee in accordance with this Indenture, (3) issued and delivered by the Company and (4) paid for, all as contemplated by and in accordance with the aforesaid Company Order or Orders, as the case may be, will have been duly issued under this Indenture and will constitute valid and legally binding obligations of the Company, entitled to the benefits provided by the Indenture, and enforceable in accordance with their terms, subject, as to enforcement, to laws relating to or affecting generally the enforcement of mortgagees’ and other creditors’ rights, including, without limitation, bankruptcy, insolvency, reorganization, receivership, moratorium and other laws affecting the rights and remedies of creditors and mortgagees generally and general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).
With respect to Securities of a series subject to a Periodic Offering, the Trustee may conclusively rely, as to the authorization by the Company of any of such Securities, the form and terms thereof and the legality, validity, binding effect and enforceability thereof, and compliance of the authentication and delivery thereof with the terms and conditions of this Indenture, upon the Opinion of Counsel and other documents delivered pursuant to Sections 201 and 301 and this Section, as applicable, at or prior to the time of the first authentication of Securities of such series unless and until such opinion or other documents have been superseded or revoked or expire by their terms. In connection with the authentication and delivery of Securities of a series subject to a Periodic Offering, the Trustee shall be entitled to assume that the Company’s instructions to authenticate and deliver such Securities do not violate any applicable law or any applicable rule, regulation or order of any Governmental Authority having jurisdiction over the Company.
If the form or terms of the Securities of any series have been established by or pursuant to a Board Resolution or an Officer’s Certificate as permitted by Sections 201 or 301, the Trustee shall not be required to authenticate such Securities if the issuance of such Securities pursuant to this Indenture will materially or adversely affect the Trustee’s own rights, duties or immunities under the Securities and this Indenture or otherwise in a manner which is not reasonably acceptable to the Trustee.
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Unless otherwise specified as contemplated by Section 301 with respect to any series of Securities, or any Tranche thereof, each Security shall be dated the date of its authentication.
Unless otherwise specified as contemplated by Section 301 with respect to any series of Securities, or any Tranche thereof, no Security shall be entitled to any benefit under this Indenture or be valid or obligatory for any purpose unless there appears on such Security a certificate of authentication substantially in the form provided for herein executed by the Trustee or an Authenticating Agent by manual signature, and such certificate upon any Security shall be conclusive evidence, and the only evidence, that such Security has been duly authenticated and delivered hereunder and is entitled to the benefits of this Indenture. Notwithstanding the foregoing, if any Security shall have been authenticated and delivered hereunder to the Company, or any Person acting on its behalf, but shall never have been issued and sold by the Company, and the Company shall deliver such Security to the Security Registrar for cancellation as provided in Section 309 together with a written statement (which need not comply with Section 102 and need not be accompanied by an Opinion of Counsel) stating that such Security has never been issued and sold by the Company, for all purposes of this Indenture such Security shall be deemed never to have been authenticated and delivered hereunder and shall never be entitled to the benefits hereof.
SECTION 304. Temporary Securities.
Pending the preparation of definitive Securities of any series, or any Tranche thereof, the Company may execute, and upon Company Order the Trustee shall authenticate and deliver, temporary Securities which are printed, lithographed, typewritten, mimeographed or otherwise produced, in any authorized denomination, substantially of the tenor of the definitive Securities in lieu of which they are issued, with such appropriate insertions, omissions, substitutions and other variations as any officer executing such Securities may determine, as evidenced by such officer’s execution of such Securities; provided, however, that temporary Securities need not recite specific redemption, sinking fund, conversion or exchange provisions.
Unless otherwise specified as contemplated by Section 301 with respect to the Securities of any series, or any Tranche thereof, after the preparation of definitive Securities of such series or Tranche, the temporary Securities of such series or Tranche shall be exchangeable, without charge to the Holder thereof, for definitive Securities of such series or Tranche upon surrender of such temporary Securities at the office or agency of the Company maintained pursuant to Section 602 in a Place of Payment for such Securities. Upon such surrender of temporary Securities for such exchange, the Company shall, except as aforesaid, execute and the Trustee shall authenticate and deliver in exchange therefor definitive Securities of the same series and Tranche of authorized denominations and of like tenor and aggregate principal amount.
Until exchanged in full as hereinabove provided, temporary Securities shall in all respects be entitled to the same benefits under this Indenture as definitive Securities of the same series and Tranche and of like tenor authenticated and delivered hereunder.
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SECTION 305. Registration, Registration of Transfer and Exchange.
The Company shall cause to be kept in each office designated pursuant to Section 602, with respect to the Securities of each series, a register (all registers kept in accordance with this Section being collectively referred to as the “Security Register”) in which, subject to such reasonable regulations as it may prescribe, the Company shall provide for the registration of Securities of such series, or any Tranche thereof, and the registration of transfer thereof. The Company shall designate one Person to maintain the Security Register for the Securities of each series on a consolidated basis, and such Person is referred to herein, with respect to such series, as the “Security Registrar.” Anything herein to the contrary notwithstanding, the Company may designate one or more of its offices as an office in which a register with respect to the Securities of one or more series shall be maintained, and the Company may designate itself the Security Registrar with respect to one or more of such series. The Security Register shall be open for inspection by the Trustee and the Company at all reasonable times.
Except as otherwise specified as contemplated by Section 301 with respect to the Securities of any series, or any Tranche thereof, upon surrender for registration of transfer of any Security of such series or Tranche at the office or agency of the Company maintained pursuant to Section 602 in a Place of Payment for such series or Tranche, the Company shall execute, and the Trustee shall authenticate and deliver, in the name of the designated transferee or transferees, one or more new Securities of the same series and Tranche, of authorized denominations and of like tenor and aggregate principal amount.
Except as otherwise specified as contemplated by Section 301 with respect to the Securities of any series, or any Tranche thereof, any Security of such series or Tranche may be exchanged at the option of the Holder, for one or more new Securities of the same series and Tranche, of authorized denominations and of like tenor and aggregate principal amount, upon surrender of the Securities to be exchanged at any such office or agency. Whenever any Securities are so surrendered for exchange, the Company shall execute, and the Trustee shall authenticate and deliver, the Securities which the Holder making the exchange is entitled to receive.
All Securities delivered upon any registration of transfer or exchange of Securities shall be valid obligations of the Company, evidencing the same debt, and entitled to the same benefits under this Indenture, as the Securities surrendered upon such registration of transfer or exchange.
Every Security presented or surrendered for registration of transfer or for exchange shall (if so required by the Company, the Trustee or the Security Registrar) be duly endorsed or shall be accompanied by a written instrument of transfer in form satisfactory to the Company, the Trustee or the Security Registrar, as the case may be, duly executed by the Holder thereof or his attorney duly authorized in writing.
Unless otherwise specified as contemplated by Section 301 with respect to Securities of any series, or any Tranche thereof, no service charge shall be made for any registration of transfer or exchange of Securities, but the Company may require payment of a
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sum sufficient to cover any tax or other governmental charge that may be imposed in connection with any registration of transfer or exchange of Securities, other than exchanges pursuant to Section 304, 406 or 1206 not involving any transfer.
The Company shall not be required to execute or to provide for the registration of transfer of or the exchange of (a) Securities of any series, or any Tranche thereof, during a period of 15 days immediately preceding the date notice is to be given identifying the serial numbers of the Securities of such series or Tranche called for redemption or (b) any Security so selected for redemption in whole or in part, except the unredeemed portion of any Security being redeemed in part.
SECTION 306. Mutilated, Destroyed, Lost and Stolen Securities.
If any mutilated Security is surrendered to the Trustee, the Company shall execute and the Trustee shall authenticate and deliver in exchange therefor a new Security of the same series and Tranche, and of like tenor and principal amount and bearing a number not contemporaneously outstanding.
If there shall be delivered to the Company and the Trustee (a) evidence to their satisfaction of the ownership of and the destruction, loss or theft of any Security and (b) such security or indemnity as may be reasonably required by them to save each of them and any agent of either of them harmless, then, in the absence of notice to the Company or the Trustee that such Security is held by a Person purporting to be the owner of such Security, the Company shall execute and the Trustee shall authenticate and deliver, in lieu of any such destroyed, lost or stolen Security, a new Security of the same series and Tranche, and of like tenor and principal amount and bearing a number not contemporaneously outstanding.
Notwithstanding the foregoing, in case any such mutilated, destroyed, lost or stolen Security has become or is about to become due and payable, the Company in its discretion may, instead of issuing a new Security, pay such Security.
Upon the issuance of any new Security under this Section, the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other reasonable expenses (including the fees and expenses of the Trustee) connected therewith.
Every new Security of any series issued pursuant to this Section in lieu of any destroyed, lost or stolen Security shall constitute an original additional contractual obligation of the Company, whether or not the destroyed, lost or stolen Security shall be at any time enforceable by anyone other than the Holder of such new Security, and any such new Security shall be entitled to all the benefits of this Indenture equally and proportionately with any and all other Securities of such series duly issued hereunder.
The provisions of this Section are exclusive and shall preclude (to the extent lawful) all other rights and remedies with respect to the replacement or payment of mutilated, destroyed, lost or stolen Securities.
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SECTION 307. Payment of Interest; Interest Rights Preserved.
Unless otherwise specified as contemplated by Section 301 with respect to the Securities of any series, or any Tranche thereof, interest on any Security which is payable, and is punctually paid or duly provided for, on any Interest Payment Date shall be paid to the Person in whose name that Security (or one or more Predecessor Securities) is registered at the close of business on the Regular Record Date for such interest.
Subject to Section 312, any interest on any Security of any series which is payable, but is not punctually paid or duly provided for, on any Interest Payment Date (herein called “Defaulted Interest”) shall forthwith cease to be payable to the Holder on the related Regular Record Date by virtue of having been such Holder, and such Defaulted Interest may be paid by the Company, at its election in each case, as provided in clause (a) or (b) below:
(a) The Company may elect to make payment of any Defaulted Interest to the Persons in whose names the Securities of such series (or their respective Predecessor Securities) are registered at the close of business on a date (herein called a “Special Record Date”) for the payment of such Defaulted Interest, which shall be fixed in the following manner. The Company shall notify the Trustee in writing of the amount of Defaulted Interest proposed to be paid on each Security of such series and the date of the proposed payment, and at the same time the Company shall deposit with the Trustee an amount of money equal to the aggregate amount proposed to be paid in respect of such Defaulted Interest or shall make arrangements satisfactory to the Trustee for such deposit on or prior to the date of the proposed payment, such money when deposited to be held in trust for the benefit of the Persons entitled to such Defaulted Interest as in this clause provided. Thereupon the Trustee shall fix a Special Record Date for the payment of such Defaulted Interest which shall be not more than 15 days and not less than 10 days prior to the date of the proposed payment and not less than 10 days after the receipt by the Trustee of the notice of the proposed payment. The Trustee shall promptly notify the Company of such Special Record Date and, in the name and at the expense of the Company, shall promptly cause notice of the proposed payment of such Defaulted Interest and the Special Record Date therefor to be mailed, first-class postage prepaid, to each Holder of Securities of such series at the address of such Holder as it appears in the Security Register, not less than 10 days prior to such Special Record Date. Notice of the proposed payment of such Defaulted Interest and the Special Record Date therefor having been so mailed, such Defaulted Interest shall be paid to the Persons in whose names the Securities of such series (or their respective Predecessor Securities) are registered at the close of business on such Special Record Date.
(b) The Company may make payment of any Defaulted Interest on the Securities of any series in any other lawful manner not inconsistent with the requirements of any securities exchange on which such Securities may be listed, and upon such notice as may be required by such exchange, if, after notice given by the Company to the Trustee of the proposed payment pursuant to this clause, such manner of payment shall be deemed practicable by the Trustee.
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Subject to the foregoing provisions of this Section and Section 305, each Security delivered under this Indenture upon registration of transfer of or in exchange for or in lieu of any other Security shall carry the rights to interest accrued and unpaid, and to accrue, which were carried by such other Security.
SECTION 308. Persons Deemed Owners.
Prior to due presentment of a Security for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name such Security is registered as the absolute owner of such Security for the purpose of receiving payment of principal of and premium, if any, and (subject to Sections 305 and 307) interest, if any, on such Security and for all other purposes whatsoever, whether or not such Security be overdue, and neither the Company, the Trustee nor any agent of the Company or the Trustee shall be affected by notice to the contrary.
SECTION 309. Cancellation by Security Registrar.
All Securities surrendered for payment, redemption, registration of transfer or exchange or for credit against any sinking fund payment shall, if surrendered to any Person other than the Security Registrar, be delivered to the Security Registrar and, if not theretofore canceled, shall be promptly canceled by the Security Registrar. The Company may at any time deliver to the Security Registrar for cancellation any Securities previously authenticated and delivered hereunder which the Company may have acquired in any manner whatsoever or which the Company shall not have issued and sold, and all Securities so delivered shall be promptly canceled by the Security Registrar. No Securities shall be authenticated in lieu of or in exchange for any Securities canceled as provided in this Section, except as expressly permitted by this Indenture. All canceled Securities held by the Security Registrar shall be disposed of in accordance with the customary practices of the Security Registrar at the time in effect, and the Security Registrar shall not be required to destroy any such certificates. The Security Registrar shall promptly deliver a certificate of disposition to the Trustee and the Company unless, by a Company Order, similarly delivered, the Company shall direct that canceled Securities be returned to it. The Security Registrar shall promptly deliver evidence of any cancellation of a Security in accordance with this Section 309 to the Trustee and the Company.
SECTION 310. Computation of Interest.
Except as otherwise specified as contemplated by Section 301 for Securities of any series, or Tranche thereof, interest on the Securities of each series shall be computed on the basis of a three hundred and sixty (360) day year consisting of twelve (12) 30-day months and, with respect to any period less than a full month, on the basis of the actual number of days elapsed during such period. For example, the interest for a period running from the 15th day of one month to the 15th day of the next month would be calculated on the basis of one 30-day month.
SECTION 311. Payment to Be in Proper Currency.
In the case of the Securities of any series, or any Tranche thereof, denominated in any currency other than Dollars or in a composite currency (the “Required Currency”), except as
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otherwise specified with respect to such Securities as contemplated by Section 301, the obligation of the Company to make any payment of the principal thereof, or the premium or interest thereon, shall not be discharged or satisfied by any tender by the Company, or recovery by the Trustee, in any currency other than the Required Currency, except to the extent that such tender or recovery shall result in the Trustee timely holding the full amount of the Required Currency then due and payable. If any such tender or recovery is in a currency other than the Required Currency, the Trustee may take such actions as it considers appropriate to exchange such currency for the Required Currency. The costs and risks of any such exchange, including without limitation the risks of delay and exchange rate fluctuation, shall be borne by the Company, the Company shall remain fully liable for any shortfall or delinquency in the full amount of Required Currency then due and payable, and in no circumstances shall the Trustee be liable therefor except in the case of its negligence or willful misconduct.
SECTION 312. Extension of Interest Payment.
The Company shall have the right at any time, so long as the Company is not in default in the payment of interest on the Securities of any series hereunder, to extend interest payment periods on all Securities of one or more series, if so specified as contemplated by Section 301 with respect to such Securities and upon such terms as may be specified as contemplated by Section 301 with respect to such Securities.
ARTICLE FOUR
Redemption of Securities
SECTION 401. Applicability of Article.
Securities of any series, or any Tranche thereof, which are redeemable before their Stated Maturity shall be redeemable in accordance with their terms and (except as otherwise specified as contemplated by Section 301 for Securities of such series or Tranche) in accordance with this Article.
SECTION 402. Election to Redeem; Notice to Trustee.
The election of the Company to redeem any Securities shall be evidenced by a Board Resolution or an Officer’s Certificate. The Company shall, at least 45 days prior to the Redemption Date fixed by the Company (unless a shorter notice shall be satisfactory to the Trustee), notify the Trustee in writing of such Redemption Date and of the principal amount of such Securities to be redeemed. In the case of any redemption of Securities (a) prior to the expiration of any restriction on such redemption provided in the terms of such Securities or elsewhere in this Indenture or (b) pursuant to an election of the Company which is subject to a condition specified in the terms of such Securities, the Company shall furnish the Trustee with an Officer’s Certificate evidencing compliance with such restriction or condition.
SECTION 403. Selection of Securities to Be Redeemed.
If less than all the Securities of any series, or any Tranche thereof, are to be redeemed, the particular Securities to be redeemed shall be selected by the Trustee from the
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Outstanding Securities of such series or Tranche not previously called for redemption, by such method as shall be provided for any particular series, or, in the absence of any such provision, by such method as the Trustee shall deem fair and appropriate and which may provide for the selection for redemption of portions (equal to the minimum authorized denomination for Securities of such series or Tranche or any integral multiple thereof) of the principal amount of Securities of such series or Tranche of a denomination larger than the minimum authorized denomination for Securities of such series or Tranche; provided, however, that if, as indicated in an Officer’s Certificate, the Company shall have offered to purchase all or any principal amount of the Securities then Outstanding of any series, or any Tranche thereof, and less than all of such Securities as to which such offer was made shall have been tendered to the Company for such purchase, the Trustee, if so directed by Company Order, shall select for redemption all or any principal amount of such Securities which have not been so tendered.
The Trustee shall promptly notify the Company and the Security Registrar in writing of the Securities selected for redemption and, in the case of any Securities selected to be redeemed in part, the principal amount thereof to be redeemed.
For all purposes of this Indenture, unless the context otherwise requires, all provisions relating to the redemption of Securities shall relate, in the case of any Securities redeemed or to be redeemed only in part, to the portion of the principal amount of such Securities which has been or is to be redeemed.
SECTION 404. Notice of Redemption.
Except as otherwise specified as contemplated by Section 301 for Securities of any series, notice of redemption shall be given in the manner provided in Section 106 to the Holders of the Securities to be redeemed not less than 30 nor more than 60 days prior to the Redemption Date.
Except as otherwise specified as contemplated by Section 301 for Securities of any series, all notices of redemption shall state:
(a) the Redemption Date,
(b) the Redemption Price (if known),
(c) if less than all the Securities of any series or Tranche are to be redeemed, the identification of the particular Securities to be redeemed and the portion of the principal amount of any Security to be redeemed in part,
(d) that on the Redemption Date the Redemption Price, together with accrued interest, if any, to the Redemption Date, will become due and payable upon each such Security to be redeemed and, if applicable, that interest thereon will cease to accrue on and after said date,
(e) the place or places where such Securities are to be surrendered for payment of the Redemption Price and accrued interest, if any, unless it shall have been specified as contemplated by Section 301 with respect to such Securities that such surrender shall not be required,
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(f) that the redemption is for a sinking or other fund, if such is the case,
(g) the CUSIP, ISIN or other similar numbers, if any, assigned to such Securities; provided, however, that such notice may state that no representation is made as to the correctness of CUSIP, ISIN or other similar numbers, in which case none of the Company, the Trustee or any agent of the Company or the Trustee shall have any liability in respect of the use of any CUSIP, ISIN or other similar number or numbers on such notices, and the redemption of such Securities shall not be affected by any defect in or omission of such numbers, and
(h) such other matters as the Company shall deem desirable or appropriate.
Unless otherwise specified with respect to any Securities in accordance with Section 301, with respect to any notice of redemption of Securities at the election of the Company, unless, upon the giving of such notice, such Securities shall be deemed to have been paid in accordance with Section 701, such notice may state that such redemption shall be conditional upon the receipt by the Paying Agent or Agents for such Securities, on or prior to the date fixed for such redemption, of money sufficient to pay the principal of and premium, if any, and interest, if any, on such Securities and that if such money shall not have been so received such notice shall be of no force or effect and the Company shall not be required to redeem such Securities. In the event that such notice of redemption contains such a condition and such money is not so received, the redemption shall not be made and within a reasonable time thereafter notice shall be given, in the manner in which the notice of redemption was given, that such money was not so received and such redemption was not required to be made, and the Paying Agent or Agents for the Securities otherwise to have been redeemed shall promptly return to the Holders thereof any of such Securities which had been surrendered for payment upon such redemption.
Notice of redemption of Securities to be redeemed at the election of the Company, and any notice of non-satisfaction of a condition for redemption as aforesaid, shall be given by the Company or, at the Company’s request, by the Security Registrar in the name and at the expense of the Company. Notice of mandatory redemption of Securities shall be given by the Security Registrar in the name and at the expense of the Company.
SECTION 405. Securities Payable on Redemption Date.
Notice of redemption having been given as aforesaid, and the conditions, if any, set forth in such notice having been satisfied, the Securities or portions thereof so to be redeemed shall, on the Redemption Date, become due and payable at the Redemption Price therein specified, and from and after such date (unless, in the case of an unconditional notice of redemption, the Company shall default in the payment of the Redemption Price and accrued interest, if any) such Securities or portions thereof, if interest-bearing, shall cease to bear interest. Upon surrender of any such Security for redemption in accordance with such notice, such Security or portion thereof shall be paid by the Company at the Redemption Price, together with
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accrued interest, if any, to the Redemption Date; provided, however, that no such surrender shall be a condition to such payment if so specified as contemplated by Section 301 with respect to such Security; and provided, further, that except as otherwise specified as contemplated by Section 301 with respect to such Security, any installment of interest on any Security the Stated Maturity of which installment is on or prior to the Redemption Date shall be payable to the Holder of such Security, or one or more Predecessor Securities, registered as such at the close of business on the related Regular Record Date according to the terms of such Security and subject to the provisions of Section 307.
SECTION 406. Securities Redeemed in Part.
Upon the surrender of any Security which is to be redeemed only in part at a Place of Payment therefor (with, if the Company or the Trustee so requires, due endorsement by, or a written instrument of transfer in form satisfactory to the Company and the Trustee duly executed by, the Holder thereof or his attorney duly authorized in writing), the Company shall execute, and the Trustee shall authenticate and deliver to the Holder of such Security, without service charge, a new Security or Securities of the same series and Tranche, of any authorized denomination requested by such Holder and of like tenor and in aggregate principal amount equal to and in exchange for the unredeemed portion of the principal of the Security so surrendered.
ARTICLE FIVE
Sinking Funds
SECTION 501. Applicability of Article.
The provisions of this Article shall be applicable to any sinking fund for the retirement of the Securities of any series, or any Tranche thereof, except as otherwise specified as contemplated by Section 301 for Securities of such series or Tranche.
The minimum amount of any sinking fund payment provided for by the terms of Securities of any series, or any Tranche thereof, is herein referred to as a “mandatory sinking fund payment”, and any payment in excess of such minimum amount provided for by the terms of Securities of any series, or any Tranche thereof, is herein referred to as an “optional sinking fund payment”. If provided for by the terms of Securities of any series, or any Tranche thereof, the cash amount of any sinking fund payment may be subject to reduction as provided in Section 502. Each sinking fund payment shall be applied to the redemption of Securities of the series or Tranche in respect of which it was made as provided for by the terms of such Securities.
SECTION 502. Satisfaction of Sinking Fund Payments with Securities.
The Company (a) may deliver to the Trustee Outstanding Securities (other than any previously called for redemption) of a series or Tranche in respect of which a mandatory sinking fund payment is to be made and (b) may apply as a credit Securities of such series or Tranche which have been redeemed either at the election of the Company pursuant to the terms of such Securities or through the application of permitted optional sinking fund payments pursuant to the terms of such Securities, in each case in satisfaction of all or any part of such
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mandatory sinking fund payment with respect to the Securities of such series; provided, however, that no Securities shall be applied in satisfaction of a mandatory sinking fund payment if such Securities shall have been previously so applied. Securities so applied shall be received and credited for such purpose by the Trustee at the Redemption Price specified in such Securities for redemption through operation of the sinking fund and the amount of such mandatory sinking fund payment shall be reduced accordingly.
SECTION 503. Redemption of Securities for Sinking Fund.
Not less than 45 days prior to each sinking fund payment date for the Securities of any series, or any Tranche thereof, the Company shall deliver to the Trustee an Officer’s Certificate specifying:
(a) the amount of the next succeeding mandatory sinking fund payment for such series or Tranche;
(b) the amount, if any, of the optional sinking fund payment to be made together with such mandatory sinking fund payment;
(c) the aggregate sinking fund payment;
(d) the portion, if any, of such aggregate sinking fund payment which is to be satisfied by the payment of cash; and
(e) the portion, if any, of such aggregate sinking fund payment which is to be satisfied by delivering and crediting Securities of such series or Tranche pursuant to Section 502 and stating the basis for such credit and that such Securities have not previously been so credited, and the Company shall also deliver to the Trustee any Securities to be so delivered.
If the Company shall have not delivered such Officer’s Certificate and, to the extent applicable, all such Securities, the next succeeding sinking fund payment for such series or Tranche shall be made entirely in cash in the amount of the mandatory sinking fund payment. Not less than 30 days before each such sinking fund payment date the Trustee shall select the Securities to be redeemed upon such sinking fund payment date in the manner specified in Section 403 and cause notice of the redemption thereof to be given in the name of and at the expense of the Company in the manner provided in Section 404. Such notice having been duly given, the redemption of such Securities shall be made upon the terms and in the manner stated in Sections 405 and 406.
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ARTICLE SIX
Covenants
SECTION 601. Payment of Principal, Premium and Interest.
The Company shall pay the principal of and premium, if any, and interest, if any, on the Securities of each series in accordance with the terms of such Securities and this Indenture.
SECTION 602. Maintenance of Office or Agency.
The Company shall maintain in each Place of Payment for the Securities of each series, or any Tranche thereof, an office or agency where payment of such Securities shall be made, where the registration of transfer or exchange of such Securities may be effected and where notices and demands to or upon the Company in respect of such Securities and this Indenture may be served. The Company shall give prompt written notice to the Trustee of the location, and any change in the location, of each such office or agency and prompt notice to the Holders of any such change in the manner specified in Section 106. If at any time the Company shall fail to maintain any such required office or agency in respect of Securities of any series, or any Tranche thereof, or shall fail to furnish the Trustee with the address thereof, payment of such Securities shall be made, registration of transfer or exchange thereof may be effected and notices and demands in respect thereof may be served at the Corporate Trust Office of the Trustee, and the Company hereby appoints the Trustee as its agent for all such purposes in any such event.
The Company may also from time to time designate one or more other offices or agencies with respect to the Securities of one or more series, or any Tranche thereof, for any or all of the foregoing purposes and may from time to time rescind such designations; provided, however, that, unless otherwise specified as contemplated by Section 301 with respect to the Securities of such series or Tranche, no such designation or rescission shall in any manner relieve the Company of its obligation to maintain an office or agency for such purposes in each Place of Payment for such Securities in accordance with the requirements set forth above. The Company shall give prompt written notice to the Trustee, and prompt notice to the Holders in the manner specified in Section 106, of any such designation or rescission and of any change in the location of any such other office or agency.
Anything herein to the contrary notwithstanding, any office or agency required by this Section may be maintained at an office of the Company or an Affiliate of the Company, in which event the Company or such Affiliate shall perform all functions to be performed at such office or agency.
SECTION 603. Money for Securities Payments to Be Held in Trust.
If the Company shall at any time act as its own Paying Agent with respect to the Securities of any series, or any Tranche thereof, it shall, on or before each due date of the principal of and premium, if any, and interest, if any, on any of such Securities, segregate and hold in trust for the benefit of the Persons entitled thereto a sum sufficient to pay the principal and premium or interest so becoming due until such sums shall be paid to such Persons or
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otherwise disposed of as herein provided. The Company shall promptly notify the Trustee of any failure by the Company (or any other obligor on such Securities) to make any payment of principal of or premium, if any, or interest, if any, on such Securities.
Whenever the Company shall have one or more Paying Agents for the Securities of any series, or any Tranche thereof, it shall, on or before each due date of the principal of and premium, if any, and interest, if any, on such Securities, deposit with such Paying Agents sums sufficient (without duplication) to pay the principal and premium or interest so becoming due, such sums to be held in trust for the benefit of the Persons entitled to such principal, premium or interest, and (unless such Paying Agent is the Trustee) the Company shall promptly notify the Trustee of any failure by it so to act.
The Company shall cause each Paying Agent for the Securities of any series, or any Tranche thereof, other than the Company or the Trustee, to execute and deliver to the Trustee an instrument in which such Paying Agent shall agree with the Trustee, subject to the provisions of this Section, that such Paying Agent shall:
(a) hold all sums held by it for the payment of the principal of and premium, if any, or interest, if any, on such Securities in trust for the benefit of the Persons entitled thereto until such sums shall be paid to such Persons or otherwise disposed of as herein provided;
(b) give the Trustee notice of any failure by the Company (or any other obligor upon such Securities) to make any payment of principal of or premium, if any, or interest, if any, on such Securities; and
(c) at any time during the continuance of any such failure, upon the written request of the Trustee, forthwith pay to the Trustee all sums so held in trust by such Paying Agent and furnish to the Trustee such information as it possesses regarding the names and addresses of the Persons entitled to such sums.
The Company may at any time pay, or by Company Order direct any Paying Agent to pay, to the Trustee all sums held in trust by the Company or such Paying Agent, such sums to be held by the Trustee upon the same trusts as those upon which such sums were held by the Company or such Paying Agent and, if so stated in a Company Order delivered to the Trustee, in accordance with the provisions of Article Seven; and, upon such payment by any Paying Agent to the Trustee, such Paying Agent shall be released from all further liability with respect to such money.
Any money deposited with the Trustee or any Paying Agent, or then held by the Company, in trust for the payment of the principal of and premium, if any, or interest, if any, on any Security and remaining unclaimed for two years after such principal and premium, if any, or interest, if any, has become due and payable shall to the extent permitted by law be paid to the Company on Company Request, or, if then held by the Company, shall be discharged from such trust; and, upon such payment or discharge, the Holder of such Security shall, as an unsecured general creditor and not as the Holder of an Outstanding Security, look only to the Company for payment of the amount so due and payable and remaining unpaid unless the applicable law provides otherwise, and all liability of the Trustee or such Paying Agent with respect to such
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trust money, and all liability of the Company as trustee thereof, shall thereupon cease; provided, however, that the Trustee or such Paying Agent, before being required to make any such payment to the Company, may at the expense of the Company cause to be mailed, on one occasion only, notice to such Holder that such money remains unclaimed and that, after a date specified therein, which shall not be less than thirty (30) days from the date of such mailing, any unclaimed balance of such money then remaining will be paid to the Company.
SECTION 604. Corporate Existence.
Subject to the rights of the Company under Article Eleven, the Company shall do or cause to be done all things necessary to preserve and keep in full force and effect its corporate existence.
SECTION 605. Maintenance of Properties.
The Company shall cause (or, with respect to property owned in common with others, make reasonable effort to cause) all its properties used or useful in the conduct of its business to be maintained and kept in good condition, repair and working order and shall cause (or, with respect to property owned in common with others, make reasonable effort to cause) to be made all necessary repairs, renewals, replacements, betterments and improvements thereof, all as, in the judgment of the Company, may be necessary so that the business carried on in connection therewith may be properly conducted; provided, however, that nothing in this Section shall prevent the Company from discontinuing, or causing the discontinuance of, the operation and maintenance of any of its properties if such discontinuance is, in the judgment of the Company, desirable in the conduct of its business.
SECTION 606. Annual Officer’s Certificate as to Compliance.
Not later than June 1 in each year, commencing June 1, 2005, the Company shall deliver to the Trustee an Officer’s Certificate which need not comply with Section 102, executed by the principal executive officer, the principal financial officer or the principal accounting officer of the Company, as to such officer’s knowledge of the Company’s compliance with all conditions and covenants under this Indenture, such compliance to be determined without regard to any period of grace or requirement of notice under this Indenture, and making any other statements as may be required by the provisions of Section 314(a)(4) of the Trust Indenture Act.
SECTION 607. Waiver of Certain Covenants.
The Company may omit in any particular instance to comply with any term, provision or condition set forth in (a) Section 602 or any additional covenant or restriction specified with respect to the Securities of any series, or any Tranche thereof, as contemplated by Section 301, if before the time for such compliance the Holders of a majority in aggregate principal amount of the Outstanding Securities of all series and Tranches with respect to which compliance with Section 602 or such additional covenant or restriction is to be omitted, considered as one class, shall, by Act of such Holders, either waive such compliance in such instance or generally waive compliance with such term, provision or condition and (b) Section 604, 605 or Article Eleven if before the time for such compliance the Holders of a majority in principal amount of Securities Outstanding under this Indenture shall, by Act of such
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Holders, either waive such compliance in such instance or generally waive compliance with such term, provision or condition; but, in the case of (a) or (b), no such waiver shall extend to or affect such term, provision or condition except to the extent so expressly waived, and, until such waiver shall become effective, the obligations of the Company and the duties of the Trustee in respect of any such term, provision or condition shall remain in full force and effect.
SECTION 608. Limitation on Liens.
(a) Except as otherwise specified as contemplated by Section 301 for Securities of any series, so long as any Securities of any series are Outstanding, the Company will not pledge, mortgage, hypothecate or grant a security interest in, or permit any mortgage, pledge, security interest or other lien upon, any capital stock of any Subsidiary now or hereafter owned by the Company, to secure any Indebtedness (hereinafter defined) without concurrently making effective provision whereby the Outstanding Securities shall (so long as such other Indebtedness shall be so secured) be equally and ratably secured with any and all such other Indebtedness and any other indebtedness similarly entitled to be equally and ratably secured; provided, however, that this restriction shall not apply to nor prevent the creation or existence of:
(1) any mortgage, pledge, security interest, lien or encumbrance upon any such capital stock created at the time of the acquisition of such capital stock by the Company or within 270 days after such time to secure all or a portion of the purchase price for such capital stock;
(2) any mortgage, pledge, security interest, lien or encumbrance upon any such capital stock existing thereon at the time of the acquisition thereof by the Company (whether or not the obligations secured thereby are assumed by the Company);
(3) any extension, renewal or refunding of any mortgage, pledge, security interest, lien or encumbrance permitted by Subsection (1) or (2) above on capital stock of any Subsidiary theretofore subject thereto (or substantially the same capital stock) or any portion thereof; or
(4) any judgment, levy, execution, attachment or other similar lien arising in connection with court proceedings, provided that either
| (ii) | the execution or enforcement of each such lien is effectively stayed within 30 days after entry of the corresponding judgment (or the corresponding judgment has been discharged within such 30 day period) and the claims secured thereby are being contested in good faith by appropriate proceedings timely commenced and diligently prosecuted; |
| (iii) | the payment of each such lien is covered in full by insurance and the insurance company has not denied or contested coverage thereof; or |
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| (iv) | so long as each such lien is adequately bonded, any appropriate legal proceedings that may have been duly initiated for the review of the corresponding judgment, decree or order shall not have been fully terminated or the period within which such proceedings may be initiated shall not have expired. |
For purposes of this Section 608, “Indebtedness” means all indebtedness, whether or not represented by bonds, debentures, notes or other securities, created or assumed by the Company for the repayment of money borrowed. All indebtedness for money borrowed secured by a lien upon property owned by the Company and upon which indebtedness for money borrowed the Company customarily pays interest, although the Company has not assumed or become liable for the payment of such indebtedness for money borrowed, shall for purposes of this Section 608 be deemed to be Indebtedness of the Company. All indebtedness of others for money borrowed which is guaranteed as to payment of principal by the Company or in effect guaranteed by the Company through a contingent agreement to purchase such indebtedness for money borrowed shall for purposes of this Section 608 be deemed to be Indebtedness of the Company, but no other contingent obligation of the Company in respect of indebtedness for money borrowed or other obligations incurred by others shall for purposes of this Section 608 be deemed to be Indebtedness of the Company.
In case the Company shall propose to pledge, mortgage, hypothecate or grant a security interest in any capital stock of any Subsidiary owned by the Company to secure any Indebtedness, other than as permitted by Subsections (a)(1) to (a)(3), inclusive, of this Section, the Company will prior thereto give written notice thereof to the Trustee, and the Company will prior to or simultaneously with such pledge, mortgage, hypothecation or grant of security interest, by supplemental indenture executed to the Trustee (or to the extent legally necessary to another trustee or an additional or separate trustee), in form satisfactory to the Trustee, effectively secure (for so long as such other Indebtedness shall be so secured) all the Securities equally and ratably with such Indebtedness and with any other indebtedness for money borrowed similarly entitled to be equally and ratably secured.
(b) Except as otherwise specified as contemplated by Section 301 for Securities of any series, the provisions of Subsection (a) of this Section 608 shall not apply in the event that the Company shall pledge, mortgage, hypothecate or grant a security interest in or other lien upon any capital stock of any Subsidiary now or hereafter owned by the Company to secure any Indebtedness which would otherwise be subject to the foregoing restriction up to an aggregate amount that, together with all other Indebtedness (other than mortgages, pledges, security interests, liens or encumbrances permitted by Subsection (a) of this Section 608) which would otherwise be subject to the foregoing restriction, does not at the time exceed 5% of Consolidated Capitalization.
For purposes of this Section 608:
(1) The term “Consolidated Capitalization” means the sum obtained by adding (i) Consolidated Shareholders’ Equity, (ii) Consolidated Indebtedness for money borrowed (exclusive of any thereof which is due and payable within one year of the date such sum is determined) and, without duplication, (iii) any preference or preferred stock of the Company or any Consolidated Subsidiary which is subject to mandatory redemption or sinking fund provisions.
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(2) The term “Consolidated Shareholders’ Equity” means the total Assets of the Company and its Consolidated Subsidiaries less all liabilities of the Company and its Consolidated Subsidiaries. As used in this definition, “liabilities” means all obligations which would, in accordance with generally accepted accounting principles, be classified on a balance sheet as liabilities, including without limitation, (i) indebtedness secured by property of the Company or any of its Consolidated Subsidiaries whether or not the Company or such Consolidated Subsidiary is liable for the payment thereof unless, in the case that the Company or such Consolidated Subsidiary is not so liable, such property has not been included among the Assets of the Company or such Consolidated Subsidiary on such balance sheet, (ii) deferred liabilities, (iii) indebtedness of the Company or any of its Consolidated Subsidiaries that is expressly subordinated in right and priority of payment to other liabilities of the Company or such Consolidated Subsidiary. As used in this definition, “liabilities” includes preference or preferred stock of the Company or any Consolidated Subsidiary only to the extent of any such preference or preferred stock that is subject to mandatory redemption or sinking fund provisions.
(3) The term “Consolidated Subsidiary” means at any date any Subsidiary the financial statements of which under generally accepted accounting principles would be consolidated with those of the Company in its consolidated financial statements as of such date.
(4) The “Assets” of any Person means the whole or any part of its business, property, assets, cash and receivables.
The term “Consolidated Indebtedness” means total indebtedness as shown on the consolidated balance sheet of the Company and its Consolidated Subsidiaries.
ARTICLE SEVEN
Satisfaction and Discharge
SECTION 701. Satisfaction and Discharge of Securities.
Any Security or Securities, or any portion of the principal amount thereof, shall be deemed to have been paid for all purposes of this Indenture, and the entire indebtedness of the Company in respect thereof shall be deemed to have been satisfied and discharged, if there shall have been irrevocably deposited with the Trustee or any Paying Agent (other than the Company), in trust:
(a) money in an amount which shall be sufficient, or
(b) in the case of a deposit made prior to the Maturity of such Securities or portions thereof, Eligible Obligations, which shall not contain provisions permitting the redemption
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or other prepayment thereof at the option of the issuer thereof, the principal of and the interest on which when due, without any regard to reinvestment thereof, will provide moneys which, together with the money, if any, deposited with or held by the Trustee or such Paying Agent, shall be sufficient, or
(c) a combination of (a) or (b) which shall be sufficient,
to pay when due the principal of and premium, if any, and interest, if any, due and to become due on such Securities or portions thereof on or prior to Maturity; provided, however, that in the case of the provision for payment or redemption of less than all the Securities of any series or Tranche, such Securities or portions thereof shall have been selected by the Trustee as provided herein and, in the case of a redemption, the notice requisite to the validity of such redemption shall have been given or irrevocable authority shall have been given by the Company to the Trustee to give such notice, under arrangements satisfactory to the Trustee; and provided, further, that the Company shall have delivered to the Trustee and such Paying Agent:
(x) if such deposit shall have been made prior to the Maturity of such Securities, a Company Order stating that the money and Eligible Obligations deposited in accordance with this Section shall be held in trust, as provided in Section 703; and
(y) if Eligible Obligations shall have been deposited, an Opinion of Counsel that the obligations so deposited constitute Eligible Obligations and do not contain provisions permitting the redemption or other prepayment at the option of the issuer thereof, and an opinion of an independent public accountant of nationally recognized standing, selected by the Company, to the effect that the requirements set forth in clause (b) above have been satisfied; and
(z) if such deposit shall have been made prior to the Maturity of such Securities, an Officer’s Certificate stating the Company’s intention that, upon delivery of such Officer’s Certificate, its indebtedness in respect of such Securities or portions thereof will have been satisfied and discharged as contemplated in this Section.
Upon the deposit of money or Eligible Obligations, or both, in accordance with this Section, together with the documents required by clauses (x), (y) and (z) above, the Trustee shall, upon receipt of a Company Request, acknowledge in writing that the Security or Securities or portions thereof with respect to which such deposit was made are deemed to have been paid for all purposes of this Indenture and that the entire indebtedness of the Company in respect thereof has been satisfied and discharged as contemplated in this Section. In the event that all of the conditions set forth in the preceding paragraph shall have been satisfied in respect of any Securities or portions thereof except that, for any reason, the Officer’s Certificate specified in clause (z) shall not have been delivered, such Securities or portions thereof shall nevertheless be deemed to have been paid for all purposes of this Indenture, and the Holders of such Securities or portions thereof shall nevertheless be no longer entitled to the benefits of this Indenture or of any of the covenants of the Company under Article Six (except the covenants contained in Sections 602 and 603) or any other covenants made in respect of such Securities or portions thereof as
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contemplated by Section 301, but the indebtedness of the Company in respect of such Securities or portions thereof shall not be deemed to have been satisfied and discharged prior to Maturity for any other purpose, and the Holders of such Securities or portions thereof shall continue to be entitled to look to the Company for payment of the indebtedness represented thereby; and, upon Company Request, the Trustee shall acknowledge in writing that such Securities or portions thereof are deemed to have been paid for all purposes of this Indenture.
If payment at Stated Maturity of less than all of the Securities of any series, or any Tranche thereof, is to be provided for in the manner and with the effect provided in this Section, the Security Registrar shall select such Securities, or portions of principal amount thereof, in the manner specified by Section 403 for selection for redemption of less than all the Securities of a series or Tranche.
In the event that Securities which shall be deemed to have been paid for purposes of this Indenture, and, if such is the case, in respect of which the Company’s indebtedness shall have been satisfied and discharged, all as provided in this Section do not mature and are not to be redeemed within the 60 day period commencing with the date of the deposit of moneys or Eligible Obligations, as aforesaid, the Company shall, as promptly as practicable, give a notice, in the same manner as a notice of redemption with respect to such Securities, to the Holders of such Securities to the effect that such deposit has been made and the effect thereof.
Notwithstanding that any Securities shall be deemed to have been paid for purposes of this Indenture, as aforesaid, the obligations of the Company and the Trustee in respect of such Securities under Sections 304, 305, 306, 404, 503 (as to notice of redemption), 602, 603, 907 and 915 and this Article Seven shall survive.
The Company shall pay, and shall indemnify the Trustee or any Paying Agent with which Eligible Obligations shall have been deposited as provided in this Section against, any tax, fee or other charge imposed on or assessed against such Eligible Obligations or the principal or interest received in respect of such Eligible Obligations, including, but not limited to, any such tax payable by any entity deemed, for tax purposes, to have been created as a result of such deposit.
Anything herein to the contrary notwithstanding, (a) if, at any time after a Security would be deemed to have been paid for purposes of this Indenture, and, if such is the case, the Company’s indebtedness in respect thereof would be deemed to have been satisfied or discharged, pursuant to this Section (without regard to the provisions of this paragraph), the Trustee or any Paying Agent, as the case may be, shall be required to return the money or Eligible Obligations, or combination thereof, deposited with it as aforesaid to the Company or its representative under any applicable Federal or State bankruptcy, insolvency or other similar law, such Security shall thereupon be deemed retroactively not to have been paid and any satisfaction and discharge of the Company’s indebtedness in respect thereof shall retroactively be deemed not to have been effected, and such Security shall be deemed to remain Outstanding and (b) any satisfaction and discharge of the Company’s indebtedness in respect of any Security shall be subject to the provisions of the last paragraph of Section 603.
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SECTION 702. Satisfaction and Discharge of Indenture.
This Indenture shall upon Company Request cease to be of further effect (except as hereinafter expressly provided), and the Trustee, at the expense of the Company, shall execute proper instruments acknowledging satisfaction and discharge of this Indenture, when
(a) no Securities remain Outstanding hereunder; and
(b) the Company has paid or caused to be paid all other sums payable hereunder by the Company;
provided, however, that if, in accordance with the last paragraph of Section 701, any Security, previously deemed to have been paid for purposes of this Indenture, shall be deemed retroactively not to have been so paid, this Indenture shall thereupon be deemed retroactively not to have been satisfied and discharged, as aforesaid, and to remain in full force and effect, and the Company shall execute and deliver such instruments as the Trustee shall reasonably request to evidence and acknowledge the same.
Notwithstanding the satisfaction and discharge of this Indenture as aforesaid, the obligations of the Company and the Trustee under Sections 304, 305, 306, 404, 503 (as to notice of redemption), 602, 603, 907 and 915 and this Article Seven shall survive.
Upon satisfaction and discharge of this Indenture as provided in this Section, the Trustee shall assign, transfer and turn over to the Company, subject to the lien provided by Section 907, any and all money, securities and other property then held by the Trustee for the benefit of the Holders of the Securities other than money and Eligible Obligations held by the Trustee pursuant to Section 703 and shall execute and deliver to the Company such instruments as, in the judgment of the Company, shall be necessary, desirable or appropriate to effect or evidence the satisfaction and discharge of this Indenture.
SECTION 703. Application of Trust Money.
Neither the Eligible Obligations nor the money deposited pursuant to Section 701, nor the principal or interest payments on any such Eligible Obligations, shall be withdrawn or used for any purpose other than, and shall be held in trust for, the payment of the principal of and premium, if any, and interest, if any, on the Securities or portions of principal amount thereof in respect of which such deposit was made, all subject, however, to the provisions of Section 603; provided, however, that, so long as there shall not have occurred and be continuing an Event of Default, any cash received from such principal or interest payments on such Eligible Obligations, if not then needed for such purpose, shall, to the extent practicable and upon Company Request, be invested in Eligible Obligations of the type described in clause (b) in the first paragraph of Section 701 maturing at such times and in such amounts as shall be sufficient, together with any other moneys and the principal of and interest on any other Eligible Obligations then held by the Trustee, to pay when due the principal of and premium, if any, and interest, if any, due and to become due on such Securities or portions thereof on and prior to the Maturity thereof, and interest earned from such reinvestment shall be paid over to the Company as received, free and clear of any trust, lien or pledge under this Indenture except the lien provided by Section 907; and provided, further, that, so long as there shall not have occurred and be continuing an Event
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of Default, any moneys held in accordance with this Section on the Maturity of all such Securities in excess of the amount required to pay the principal of and premium, if any, and interest, if any, then due on such Securities shall be paid over to the Company free and clear of any trust, lien or pledge under this Indenture except the lien provided by Section 907; and provided, further, that if an Event of Default shall have occurred and be continuing, moneys to be paid over to the Company pursuant to this Section shall be held until such Event of Default shall have been waived or cured.
ARTICLE EIGHT
Events of Default; Remedies
SECTION 801. Events of Default.
“Event of Default”, wherever used herein with respect to Securities of any series, means any one of the following events:
(a) failure to pay interest, if any, on any Security of such series within 30 days after the same becomes due and payable; provided, however, that a valid extension of the interest payment period by the Company as contemplated in Section 312 of this Indenture shall not constitute a failure to pay interest for this purpose; or
(b) failure to pay the principal of or premium, if any, on any Security of such series at its Maturity; or
(c) failure to perform or breach of any covenant or warranty of the Company in this Indenture (other than a covenant or warranty a default in the performance of which or breach of which is elsewhere in this Section specifically dealt with or which has expressly been included in this Indenture solely for the benefit of one or more series of Securities other than such series) for a period of 90 days after there has been given, by registered or certified mail, to the Company by the Trustee, or to the Company and the Trustee by the Holders of at least 33% in aggregate principal amount of the Outstanding Securities of such series, a written notice specifying such default or breach and requiring it to be remedied and stating that such notice is a “Notice of Default” hereunder, unless the Trustee, or the Trustee and the Holders of a principal amount of Securities of such series not less than the principal amount of Securities the Holders of which gave such notice, as the case may be, shall agree in writing to an extension of such period prior to its expiration; provided, however, that the Trustee, or the Trustee and the Holders of such principal amount of Securities of such series, as the case may be, shall be deemed to have agreed to an extension of such period if corrective action is initiated by the Company within such period and is being diligently pursued; or
(d) the entry by a court having jurisdiction in the premises of (1) a decree or order for relief in respect of the Company in an involuntary case or proceeding under any applicable Federal or State bankruptcy, insolvency, reorganization or other similar law or (2) a decree or order adjudging the Company a bankrupt or insolvent, or approving as properly filed a petition by one or more Persons other than the Company seeking reorganization,
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arrangement, adjustment or composition of or in respect of the Company under any applicable Federal or State bankruptcy, insolvency or similar law, or appointing a custodian, receiver, liquidator, assignee, trustee, sequestrator or other similar official for the Company or for any substantial part of its property, or ordering the winding up or liquidation of its affairs, and any such decree or order for relief or any such other decree or order shall have remained unstayed and in effect for a period of 90 consecutive days; or
(e) the commencement by the Company of a voluntary case or proceeding under any applicable Federal or State bankruptcy, insolvency, reorganization or other similar law or of any other case or proceeding to be adjudicated a bankrupt or insolvent, or the consent by the Company to the entry of a decree or order for relief in respect of the Company in a case or proceeding under any applicable Federal or State bankruptcy, insolvency, reorganization or other similar law or to the commencement of any bankruptcy or insolvency case or proceeding against the Company, or the filing by the Company of a petition or answer or consent seeking reorganization or relief under any applicable Federal or State bankruptcy, insolvency, reorganization or similar law, or the consent by the Company to the filing of such petition or to the appointment of or taking possession by a custodian, receiver, liquidator, assignee, trustee, sequestrator or similar official of the Company or of any substantial part of its property, or the making by the Company of a general assignment for the benefit of creditors, or the admission by the Company in writing of its inability to pay its debts generally as they become due, or the authorization of such action by the Board of Directors of the Company; or
(f) any other Event of Default specified with respect to Securities of such series as contemplated by Section 301(o).
SECTION 802. Acceleration of Maturity; Rescission and Annulment.
If an Event of Default due to the default in payment of principal of, or interest on, any series of Securities or due to the default in the performance or breach of any other covenant or warranty of the Company applicable to the Securities of such series but not applicable to all Outstanding Securities shall have occurred and be continuing, either the Trustee or the Holders of not less than 33% in principal amount of the Securities of such series may then declare the principal amount (or, if any of the Securities of such series are Discount Securities, such portion of the principal amount as may be specified in the terms thereof as contemplated by Section 301) of all Securities of such series and interest accrued thereon to be due and payable immediately by a written notice to the Company (and to the Trustee if given by the Holders). If an Event of Default due to default in the performance of any other of the covenants or agreements herein applicable to all Outstanding Securities or an Event of Default specified in Section 801(d) or (e) shall have occurred and be continuing, either the Trustee or the Holders of not less than 33% in principal amount of all Securities then Outstanding (considered as one class), and not the Holders of the Securities of any one of such series, may declare the principal of all Securities and interest accrued thereon to be due and payable immediately by a written notice to the Company (and to the Trustee if given by the Holders). As a consequence of each such declaration (herein referred to as a declaration of acceleration) with respect to Securities of any series, the principal amount (or portion thereof in the case of Discount Securities) of such Securities and interest accrued thereon shall become due and payable immediately.
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At any time after such a declaration of acceleration with respect to Securities of any series shall have been made and before a judgment or decree for payment of the money due shall have been obtained by the Trustee as hereinafter in this Article provided, the Event or Events of Default giving rise to such declaration of acceleration shall, without further act, be deemed to have been waived, and such declaration and its consequences shall, without further act, be deemed to have been rescinded and annulled, if
(a) the Company shall have paid or deposited with the Trustee a sum sufficient to pay
(1) all overdue interest on all Securities of such series;
(2) the principal of and premium, if any, on any Securities of such series which have become due otherwise than by such declaration of acceleration and interest thereon at the rate or rates prescribed therefor in such Securities;
(3) to the extent that payment of such interest is lawful, interest upon overdue interest, if any, at the rate or rates prescribed therefor in such Securities;
(4) all amounts due to the Trustee under Section 907;
and
(b) any other Event or Events of Default with respect to Securities of such series, other than the nonpayment of the principal of Securities of such series which shall have become due solely by such declaration of acceleration, shall have been cured or waived as provided in Section 813.
No such rescission shall affect any subsequent Event of Default or impair any right consequent thereon.
SECTION 803. Collection of Indebtedness and Suits for Enforcement by Trustee.
If an Event of Default described in clause (a) or (b) of Section 801 shall have occurred and be continuing, the Company shall, upon demand of the Trustee, pay to it, for the benefit of the Holders of the Securities of the series with respect to which such Event of Default shall have occurred, the whole amount then due and payable on such Securities for principal and premium, if any, and interest, if any, and, to the extent permitted by law, interest on any overdue principal, premium and interest, at the rate or rates prescribed therefor in such Securities, and, in addition thereto, such further amount as shall be sufficient to cover any amounts due to the Trustee under Section 907.
If the Company shall fail to pay such amounts forthwith upon such demand, the Trustee, in its own name and as trustee of an express trust, may institute a judicial proceeding for the collection of the sums so due and unpaid, may prosecute such proceeding to judgment or final decree and may enforce the same against the Company or any other obligor upon such Securities and collect the moneys adjudged or decreed to be payable in the manner provided by law out of the property of the Company or any other obligor upon such Securities, wherever situated.
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If an Event of Default with respect to Securities of any series shall have occurred and be continuing, the Trustee may in its discretion proceed to protect and enforce its rights and the rights of the Holders of Securities of such series by such appropriate judicial proceedings as the Trustee shall deem most effectual to protect and enforce any such rights, whether for the specific enforcement of any covenant or agreement in this Indenture or in aid of the exercise of any power granted herein, or to enforce any other proper remedy.
SECTION 804. Trustee May File Proofs of Claim.
In case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding relative to the Company or any other obligor upon the Securities or the property of the Company or of such other obligor or their creditors, the Trustee (irrespective of whether the principal of the Securities shall then be due and payable as therein expressed or by declaration or otherwise and irrespective of whether the Trustee shall have made any demand on the Company for the payment of overdue principal or interest) shall be entitled and empowered, by intervention in such proceeding or otherwise,
(a) to file and prove a claim for the whole amount of principal, premium, if any, and interest, if any, owing and unpaid in respect of the Securities and to file such other papers or documents as may be necessary or advisable in order to have the claims of the Trustee (including any claim for amounts due to the Trustee under Section 907) and of the Holders allowed in such judicial proceeding, and
(b) to collect and receive any moneys or other property payable or deliverable on any such claims and to distribute the same;
and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Holder to make such payments to the Trustee and, in the event that the Trustee shall consent to the making of such payments directly to the Holders, to pay to the Trustee any amounts due it under Section 907.
Nothing herein contained shall be deemed to authorize the Trustee to authorize or consent to or accept or adopt on behalf of any Holder any plan of reorganization, arrangement, adjustment or composition affecting the Securities or the rights of any Holder thereof or to authorize the Trustee to vote in respect of the claim of any Holder in any such proceeding.
SECTION 805. Trustee May Enforce Claims Without Possession of Securities.
All rights of action and claims under this Indenture or the Securities may be prosecuted and enforced by the Trustee without the possession of any of the Securities or the production thereof in any proceeding relating thereto, and any such proceeding instituted by the Trustee shall be brought in its own name as trustee of an express trust, and any recovery of judgment shall, after provision for the payment of the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel, be for the ratable benefit of the Holders in respect of which such judgment has been recovered.
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SECTION 806. Application of Money Collected.
Any money or property collected or received by the Trustee pursuant to this Article and distributable in respect of the Company’s obligations under this Indenture shall be applied in the following order, to the extent permitted by law, at the date or dates fixed by the Trustee and, in case of the distribution of such money on account of principal or premium, if any, or interest, if any, upon presentation of the Securities in respect of which or for the benefit of which such money shall have been collected and the notation thereon of the payment if only partially paid and upon surrender thereof if fully paid:
First: To the payment of all amounts due the Trustee (including any predecessor Trustee) under Section 907;
Second: To the payment of the amounts then due and unpaid upon the Securities for principal of and premium, if any, and interest, if any, in respect of which or for the benefit of which such money has been collected, ratably, without preference or priority of any kind, according to the amounts due and payable on such Securities for principal, premium, if any, and interest, if any, respectively; and
Third: To the payment of the remainder, if any, to the Company or to whomsoever may be lawfully entitled to receive the same or as a court of competent jurisdiction may direct.
SECTION 807. Limitation on Suits.
No Holder shall have any right to institute any proceeding, judicial or otherwise, with respect to this Indenture, or for the appointment of a receiver or trustee, or for any other remedy hereunder, unless:
(a) such Holder shall have previously given written notice to the Trustee of a continuing Event of Default with respect to the Securities of such series;
(b) the Holders of a majority in aggregate principal amount of the Outstanding Securities of all series in respect of which an Event of Default shall have occurred and be continuing, considered as one class, shall have made written request to the Trustee to institute proceedings in respect of such Event of Default in its own name as Trustee hereunder;
(c) such Holder or Holders shall have offered to the Trustee reasonable indemnity against the costs, expenses and liabilities to be incurred in compliance with such request;
(d) the Trustee for 60 days after its receipt of such notice, request and offer of indemnity shall have failed to institute any such proceeding; and
(e) no direction inconsistent with such written request shall have been given to the Trustee during such 60-day period by the Holders of a majority in aggregate principal amount of the Outstanding Securities of all series in respect of which an Event of Default shall have occurred and be continuing, considered as one class;
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it being understood and intended that no one or more of such Holders shall have any right in any manner whatever by virtue of, or by availing of, any provision of this Indenture to affect, disturb or prejudice the rights of any other of such Holders or to obtain or to seek to obtain priority or preference over any other of such Holders or to enforce any right under this Indenture, except in the manner herein provided and for the equal and ratable benefit of all of such Holders.
SECTION 808. Unconditional Right of Holders to Receive Principal, Premium and Interest.
Notwithstanding any other provision in this Indenture, the Holder of any Security shall have the right, which is absolute and unconditional, to receive payment of the principal of and premium, if any, and (subject to Sections 307 and 312) interest, if any, on such Security on the Stated Maturity or Maturities expressed in such Security (or, in the case of redemption, on the Redemption Date) and to institute suit for the enforcement of any such payment, and such rights shall not be impaired without the consent of such Holder.
SECTION 809. Restoration of Rights and Remedies.
If the Trustee or any Holder has instituted any proceeding to enforce any right or remedy under this Indenture and such proceeding shall have been discontinued or abandoned for any reason, or shall have been determined adversely to the Trustee or to such Holder, then and in every such case, subject to any determination in such proceeding, the Company, the Trustee and such Holder shall be restored severally and respectively to their former positions hereunder and thereafter all rights and remedies of the Trustee and such Holder shall continue as though no such proceeding had been instituted.
SECTION 810. Rights and Remedies Cumulative.
Except as otherwise provided in the last paragraph of Section 306, no right or remedy herein conferred upon or reserved to the Trustee or to the Holders is intended to be exclusive of any other right or remedy, and every right and remedy shall, to the extent permitted by law, be cumulative and in addition to every other right and remedy given hereunder or now or hereafter existing at law or in equity or otherwise. The assertion or employment of any right or remedy hereunder, or otherwise, shall not prevent the concurrent assertion or employment of any other appropriate right or remedy.
SECTION 811. Delay or Omission Not Waiver.
No delay or omission of the Trustee or of any Holder to exercise any right or remedy accruing upon any Event of Default shall impair any such right or remedy or constitute a waiver of any such Event of Default or an acquiescence therein. Every right and remedy given by this Article or by law to the Trustee or to the Holders may be exercised from time to time, and as often as may be deemed expedient, by the Trustee or by the Holders, as the case may be.
SECTION 812. Control by Holders of Securities.
If an Event of Default shall have occurred and be continuing in respect of a series of Securities, the Holders of a majority in principal amount of the Outstanding Securities of such
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series shall have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or exercising any trust or power conferred on the Trustee, with respect to the Securities of such series; provided, however, that if an Event of Default shall have occurred and be continuing with respect to more than one series of Securities, the Holders of a majority in aggregate principal amount of the Outstanding Securities of all such series, considered as one class, shall have the right to make such direction, and not the Holders of the Securities of any one of such series; and provided, further, that
(a) such direction shall not be in conflict with any rule of law or with this Indenture, and could not involve the Trustee in personal liability in circumstances where indemnity would not, in the Trustee’s sole discretion, be adequate, and
(b) the Trustee may take any other action deemed proper by the Trustee that is not inconsistent with such direction.
SECTION 813. Waiver of Past Defaults.
The Holders of not less than a majority in principal amount of the Outstanding Securities of any series may on behalf of the Holders of all the Securities of such series waive any past default hereunder with respect to such series and its consequences, except a default
(a) in the payment of the principal of or premium, if any, or interest, if any, on any Security of such series, or
(b) in respect of a covenant or provision hereof which under Section 1202 cannot be modified or amended without the consent of the Holder of each Outstanding Security of such series affected.
Upon any such waiver, such default shall cease to exist, and any and all Events of Default arising therefrom shall be deemed to have been cured, for every purpose of this Indenture; but no such waiver shall extend to any subsequent or other default or impair any right consequent thereon.
SECTION 814. Undertaking for Costs.
The Company and the Trustee agree, and each Holder by his acceptance thereof shall be deemed to have agreed, that any court may in its discretion require, in any suit for the enforcement of any right or remedy under this Indenture, or in any suit against the Trustee for any action taken, suffered or omitted by it as Trustee, the filing by any party litigant in such suit of an undertaking to pay the costs of such suit, and that such court may in its discretion assess reasonable costs, including reasonable attorneys’ fees, against any party litigant in such suit, having due regard to the merits and good faith of the claims or defenses made by such party litigant; but the provisions of this Section shall not apply to any suit instituted by the Company, to any suit instituted by the Trustee, to any suit instituted by any Holder, or group of Holders, holding in the aggregate more than 10% in aggregate principal amount of the Outstanding Securities of all series in respect of which such suit may be brought, considered as one class, or to any suit instituted by any Holder for the enforcement of the payment of the principal of or premium, if any, or interest, if any, on any Security on or after the Stated Maturity or Maturities expressed in such Security (or, in the case of redemption, on or after the Redemption Date).
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SECTION 815. Waiver of Stay or Extension Laws.
The Company covenants (to the extent that it may lawfully do so) that it will not at any time insist upon, or plead, or in any manner whatsoever claim or take the benefit or advantage of, any stay or extension law wherever enacted, now or at any time hereafter in force, which may affect the covenants or the performance of this Indenture; and the Company (to the extent that it may lawfully do so) hereby expressly waives all benefit or advantage of any such law and covenants that it will not hinder, delay or impede the execution of any power herein granted to the Trustee, but will suffer and permit the execution of every such power as though no such law had been enacted.
ARTICLE NINE
The Trustee
SECTION 901. Certain Duties and Responsibilities.
(a) The Trustee shall have and be subject to all the duties and responsibilities specified with respect to an indenture trustee in the Trust Indenture Act and no implied covenants or obligations shall be read into this Indenture against the Trustee. For purposes of Sections 315(a) and 315(c) of the Trust Indenture Act, the term “default” is hereby defined as an Event of Default which has occurred and is continuing.
(b) No provision of this Indenture shall require the Trustee to expend or risk its own funds or otherwise incur any financial liability in the performance of any of its duties hereunder, or in the exercise of any of its rights or powers, if it shall have reasonable grounds for believing that repayment of such funds or adequate indemnity against such risk or liability is not reasonably assured to it.
(c) Notwithstanding anything contained in this Indenture to the contrary, the duties and responsibilities of the Trustee under this Indenture shall be subject to the protections, exculpations and limitations on liability afforded to an indenture trustee under the provisions of the Trust Indenture Act. For the purposes of Sections 315(b) and 315(d)(2) of the Trust Indenture Act, the term “responsible officer” is hereby defined as a Responsible Officer and the chairman or vice chairman of the board of directors, the chairman or vice chairman of the executive committee of the board of directors, the president, any vice president, the secretary, any assistant secretary, the treasurer any assistant treasurer, the cashier, any assistant cashier, any trust officer or assistant trust officer, the controller and any assistant controller of the Trustee, or any other officer of the Trustee customarily performing functions similar to those performed by a Responsible Officer or any of the above designated officers and also means, with respect to a particular corporate trust matter, any other officer to whom such matter is referred because of his or her knowledge of and familiarity with the particular subject.
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(d) Whether or not therein expressly so provided, every provision of this Indenture relating to the conduct or affecting the liability of or affording protection to the Trustee shall be subject to the provisions of this Section.
SECTION 902. Notice of Defaults.
The Trustee shall give notice of any default hereunder known to the Trustee with respect to the Securities of any series to the Holders of Securities of such series in the manner and to the extent that it would be required to do so if the Indenture were qualified under the Trust Indenture Act, unless such default shall have been cured or waived; provided, however, that in the case of any default of the character specified in Section 801(c), no such notice to Holders shall be given until at least 45 days after the occurrence thereof. For the purpose of this Section and clause (h) of Section 903, the term “default” means any event which is, or after notice or lapse of time, or both, would become, an Event of Default.
SECTION 903. Certain Rights of Trustee.
Subject to the provisions of Section 901 and to the applicable provisions of the Trust Indenture Act:
(a) the Trustee may conclusively rely and shall be fully protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, direction, consent, order, bond, debenture, note, other evidence of indebtedness or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties;
(b) any request or direction of the Company mentioned herein shall be sufficiently evidenced by a Company Request or Company Order, or as otherwise expressly provided herein, and any resolution of the Board of Directors may be sufficiently evidenced by a Board Resolution;
(c) whenever in the administration of this Indenture the Trustee shall deem it desirable that a matter be proved or established prior to taking, suffering or omitting any action hereunder, the Trustee (unless other evidence be herein specifically prescribed) may, in the absence of bad faith on its part, conclusively rely upon an Officer’s Certificate;
(d) the Trustee may consult with counsel and the written advice of such counsel or any Opinion of Counsel shall be full and complete authorization and protection in respect of any action taken, suffered or omitted by it hereunder in good faith and in reliance thereon;
(e) the Trustee shall be under no obligation to exercise any of the rights or powers vested in it by this Indenture at the request or direction of any Holder pursuant to this Indenture, unless such Holder shall have offered to the Trustee reasonable security or indemnity against the costs, expenses and liabilities which might be incurred by it in compliance with such request or direction;
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(f) the Trustee shall not be bound to make any investigation into the facts or matters stated in any resolution, certificate, statement, instrument, opinion, report, notice, request, direction, consent, order, bond, debenture, note, other evidence of indebtedness or other paper or document, but the Trustee, in its discretion, may make such further inquiry or investigation into such facts or matters as it may see fit, and, if the Trustee shall determine to make such further inquiry or investigation, it shall (subject to applicable legal requirements) be entitled to examine, during normal business hours, the books, records and premises of the Company, personally or by agent or attorney;
(g) the Trustee may execute any of the trusts or powers hereunder or perform any duties hereunder either directly or by or through agents or attorneys, and the Trustee shall not be responsible for any misconduct or negligence on the part of any agent or attorney appointed with due care by it hereunder;
(h) the rights, privileges, protections, immunities and benefits given to the Trustee, including, without limitation, its right to be indemnified, are extended to, and shall be enforceable by, the Trustee in each of its capacities hereunder;
(i) the Trustee shall not be charged with knowledge of any default (as defined in Section 902) or Event of Default, as the case may be, with respect to the Securities of any series for which it is acting as Trustee unless either (1) a Responsible Officer of the Trustee shall have actual knowledge that such default or Event of Default, as the case may be, exists and constitutes a default or Event of Default under this Indenture or (2) written notice of such default or Event of Default, as the case may be, shall have been given in the manner provided in Section 105 hereof to the Trustee by the Company, any other obligor on such Securities or by any Holder of such Securities; and
(j) the Trustee shall not be liable for any action it takes or omits to take in good faith which it believes to be authorized or within its rights or powers conferred upon it under this Indenture.
SECTION 904. Not Responsible for Recitals or Issuance of Securities.
The recitals contained herein and in the Securities (except the Trustee’s certificates of authentication) shall be taken as the statements of the Company, and neither the Trustee nor any Authenticating Agent assumes responsibility for their correctness. The Trustee makes no representations as to the validity or sufficiency of this Indenture or of the Securities. Neither the Trustee nor any Authenticating Agent shall be accountable for the use or application by the Company of Securities or the proceeds thereof.
SECTION 905. May Hold Securities.
Each of the Trustee, any Authenticating Agent, any Paying Agent, any Security Registrar or any other agent of the Company, in its individual or any other capacity, may become the owner or pledgee of Securities and, subject to Sections 908 and 913, may otherwise deal with the Company with the same rights it would have if it were not the Trustee, Authenticating Agent, Paying Agent, Security Registrar or such other agent.
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SECTION 906. Money Held in Trust.
Money held by the Trustee in trust hereunder need not be segregated from other funds, except to the extent required by law. The Trustee shall be under no liability for interest on any money received by it hereunder except as expressly provided herein or otherwise agreed with, and for the sole benefit of, the Company.
SECTION 907. Compensation and Reimbursement.
The Company shall
(a) pay to the Trustee from time to time reasonable compensation for all services rendered by it hereunder (which compensation shall not be limited by any provision of law in regard to the compensation of a trustee of an express trust);
(b) except as otherwise expressly provided herein, reimburse the Trustee upon its request for all reasonable expenses, disbursements and advances reasonably incurred or made by the Trustee in accordance with any provision of this Indenture (including the reasonable compensation and the expenses and disbursements of its agents and counsel), except to the extent that any such expense, disbursement or advance may be attributable to the Trustee’s negligence, willful misconduct or bad faith; and
(c) indemnify the Trustee for, and hold it harmless from and against, any loss, liability or expense reasonably incurred by it arising out of or in connection with the acceptance or administration of the trust or trusts hereunder or the performance of its duties hereunder, including the reasonable costs and expenses of defending itself against any claim or liability in connection with the exercise or performance of any of its powers or duties hereunder, except to the extent any such loss, liability or expense may be attributable to its negligence, willful misconduct or bad faith.
As security for the performance of the obligations of the Company under this Section, the Trustee shall have a lien prior to the Securities upon all property and funds held or collected by the Trustee as such other than property and funds held in trust under Section 703 (except as otherwise provided in Section 703).
In addition and without prejudice to the rights provided to the Trustee under any of the provisions of this Indenture, when the Trustee incurs expenses or renders services in connection with an Event of Default specified in Section 801(d) or Section 801(e), the expenses (including the reasonable charges and expenses of its counsel) and the compensation for the services are intended to constitute expenses of administration under any applicable Federal or State bankruptcy, insolvency or other similar law.
The Company’s obligations under this Section 907 and the lien referred to in this Section 907 shall survive the resignation or removal of the Trustee, the discharge of the Company’s obligations under Article Seven of this Indenture and/or the termination of this Indenture.
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“Trustee” for purposes of this Section shall include any predecessor Trustee; provided, however, that the negligence, willful misconduct or bad faith of any Trustee hereunder shall not affect the rights of any other Trustee hereunder.
SECTION 908. Disqualification; Conflicting Interests.
If the Trustee shall have or acquire any conflicting interest within the meaning of the Trust Indenture Act, it shall either eliminate such conflicting interest or resign to the extent, in the manner and with the effect, and subject to the conditions, provided in the Trust Indenture Act and this Indenture. For purposes of Section 310(b)(1) of the Trust Indenture Act and to the extent permitted thereby, the Trustee, in its capacity as trustee in respect of the Securities of any series, shall not be deemed to have a conflicting interest arising from its capacity as trustee in respect of the Securities of any other series or any securities of any series issued under the Indenture (For Unsecured Debt Securities Series A), dated as of October 1, 1997, of the Company to The Bank of New York, as trustee, the Indenture (For Unsecured Debt Securities Series B), dated as of October 1, 1997, of the Company to The Bank of New York, as trustee, the Indenture (For Unsecured Debt Securities Series C), dated as of January 1, 1998, of the Company to The Bank of New York, as trustee, the Purchase Contract Agreement dated as of July 1, 1998 of the Company to The Bank of New York, as agent, attorney-in-fact and trustee, the Indenture (For Unsecured Debt Securities Series D and Series E), dated as of July 1, 1998, of the Company to The Bank of New York, as trustee, the Indenture (For Unsecured Debt Securities Series F), dated as of October 1, 1998 of the Company to The Bank of New York, as trustee, the Indenture (For Unsecured Debt Securities Series G), dated as of October 1, 1998, of the Company to The Bank of New York, as trustee, the Indenture (For Unsecured Debt Securities Series H), dated as of June 1, 1999, of the Company to The Bank of New York, as trustee, the Indenture (For Unsecured Debt Securities Series I), dated as of September 1, 1999, of the Company to The Bank of New York, as trustee, the Indenture (For Unsecured Debt Securities Series J), dated as of July 1, 2001, of the Company to The Bank of New York, as trustee, the Purchase Contract Agreement, dated as of October 1, 2001, of the Company to The Bank of New York, as agent, attorney-in-fact and trustee, the Indenture (For Unsecured Debt Securities Series K and Series L), dated as of October 1, 2001, of the Company to The Bank of New York, as trustee, the Purchase Contract Agreement dated as of June 1, 2002 of the Company to The Bank of New York, as agent, attorney-in-fact and trustee, the Indenture (For Unsecured Debt Securities Series M), dated as of June 1, 2002, of the Company to The Bank of New York, as trustee, the Indenture (For Unsecured Debt Securities Series N), dated as of July 1, 2003, of the Company to The Bank of New York, as trustee, the Indenture (For Unsecured Debt Securities Series O), dated as of November 1, 2004, of the Company to The Bank of New York, as trustee, the Indenture (For Unsecured Debt Securities Series P), dated as of November 1, 2004, of the Company to The Bank of New York, as trustee, or the Indenture (For Unsecured Debt Securities Series R), dated as of November 1, 2004, of the Company to The Bank of New York, as trustee.
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SECTION 909. Corporate Trustee Required; Eligibility.
There shall at all times be a Trustee hereunder which shall be
(a) a corporation organized and doing business under the laws of the United States, any State or territory thereof or the District of Columbia, authorized under such laws to exercise corporate trust powers, having a combined capital and surplus of at least $50,000,000 and subject to supervision or examination by Federal, State or District of Columbia authority, or
(b) if and to the extent permitted by the Commission by rule, regulation or order upon application, a corporation or other Person organized and doing business under the laws of a foreign government, authorized under such laws to exercise corporate trust powers, having a combined capital and surplus of at least $50,000,000 or the Dollar equivalent of the applicable foreign currency and subject to supervision or examination by authority of such foreign government or a political subdivision thereof substantially equivalent to supervision or examination applicable to United States institutional trustees,
and, in either case, qualified and eligible under this Article and the Trust Indenture Act. If such corporation publishes reports of condition at least annually, pursuant to law or to the requirements of such supervising or examining authority, then for the purposes of this Section, the combined capital and surplus of such corporation shall be deemed to be its combined capital and surplus as set forth in its most recent report of condition so published. If at any time the Trustee shall cease to be eligible in accordance with the provisions of this Section, it shall resign immediately in the manner and with the effect hereinafter specified in this Article.
SECTION 910. Resignation and Removal; Appointment of Successor.
(a) No resignation or removal of the Trustee and no appointment of a successor Trustee pursuant to this Article shall become effective until the acceptance of appointment by the successor Trustee in accordance with the applicable requirements of Section 911.
(b) The Trustee may resign at any time with respect to the Securities of one or more series by giving written notice thereof to the Company. If the instrument of acceptance by a successor Trustee required by Section 911 shall not have been delivered to the Trustee within 30 days after the giving of such notice of resignation, the resigning Trustee may petition any court of competent jurisdiction for the appointment of a successor Trustee with respect to the Securities of such series.
(c) The Trustee may be removed at any time with respect to the Securities of any series by Act of the Holders of a majority in principal amount of the Outstanding Securities of such series delivered to the Trustee and to the Company.
(d) If at any time:
(1) the Trustee shall fail to comply with Section 908 after written request therefor by the Company or by any Holder who has been a bona fide Holder for at least six months, or
(2) the Trustee shall cease to be eligible under Section 909 or Section 310(a) of the Trust Indenture Act and shall fail to resign after written request therefor by the Company or by any such Holder, or
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(3) the Trustee shall become incapable of acting or shall be adjudged a bankrupt or insolvent or a receiver of the Trustee or of its property shall be appointed or any public officer shall take charge or control of the Trustee or of its property or affairs for the purpose of rehabilitation, conservation or liquidation,
then, in any such case, (x) the Company by a Board Resolution may remove the Trustee with respect to all Securities or (y) subject to Section 814, any Holder who has been a bona fide Holder for at least six months may, on behalf of himself and all others similarly situated, petition any court of competent jurisdiction for the removal of the Trustee with respect to all Securities and the appointment of a successor Trustee or Trustees.
(e) If the Trustee shall resign, be removed or become incapable of acting, or if a vacancy shall occur in the office of Trustee for any cause (other than as contemplated in clause (y) in Subsection (d) of this Section), with respect to the Securities of one or more series, the Company, by a Board Resolution, shall promptly appoint a successor Trustee or Trustees with respect to the Securities of that or those series (it being understood that any such successor Trustee may be appointed with respect to the Securities of one or more or all of such series and that at any time there shall be only one Trustee with respect to the Securities of any particular series) and shall comply with the applicable requirements of Section 911. If, within one year after such resignation, removal or incapability, or the occurrence of such vacancy, a successor Trustee with respect to the Securities of any series shall be appointed by Act of the Holders of a majority in principal amount of the Outstanding Securities of such series delivered to the Company and the retiring Trustee, the successor Trustee so appointed shall, forthwith upon its acceptance of such appointment in accordance with the applicable requirements of Section 911, become the successor Trustee with respect to the Securities of such series and to that extent supersede the successor Trustee appointed by the Company. If no successor Trustee with respect to the Securities of any series shall have been so appointed by the Company or the Holders and accepted appointment in the manner required by Section 911, any Holder who has been a bona fide Holder of a Security of such series for at least six months may, on behalf of itself and all others similarly situated, petition any court of competent jurisdiction for the appointment of a successor Trustee with respect to the Securities of such series.
(f) So long as no event which is, or after notice or lapse of time, or both, would become, an Event of Default shall have occurred and be continuing, and except with respect to a Trustee appointed by Act of the Holders of a majority in principal amount of the Outstanding Securities pursuant to Subsection (e) of this Section, if the Company shall have delivered to the Trustee (i) a Board Resolution appointing a successor Trustee, effective as of a date specified therein, and (ii) an instrument of acceptance of such appointment, effective as of such date, by such successor Trustee in accordance with Section 911, the Trustee shall be deemed to have resigned as contemplated in Subsection (b) of this Section, the successor Trustee shall be deemed to have been appointed by the Company pursuant to Subsection (e) of this Section and such appointment shall be deemed to have been accepted as contemplated in Section 911, all as of such date, and all other provisions of this Section and Section 911 shall be applicable to such resignation, appointment and acceptance except to the extent inconsistent with this Subsection (f).
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(g) The Company (or, should the Company fail so to act promptly, the successor trustee at the expense of the Company) shall give notice of each resignation and each removal of the Trustee with respect to the Securities of any series and each appointment of a successor Trustee with respect to the Securities of any series by mailing written notice of such event by first-class mail, postage prepaid, to all Holders of Securities of such series as their names and addresses appear in the Security Register. Each notice shall include the name of the successor Trustee with respect to the Securities of such series and the address of its corporate trust office.
SECTION 911. Acceptance of Appointment by Successor.
(a) In case of the appointment hereunder of a successor Trustee with respect to the Securities of all series, every such successor Trustee so appointed shall execute, acknowledge and deliver to the Company and to the retiring Trustee an instrument accepting such appointment, and thereupon the resignation or removal of the retiring Trustee shall become effective and such successor Trustee, without any further act, deed or conveyance, shall become vested with all the rights, powers, trusts and duties of the retiring Trustee; but, on the request of the Company or the successor Trustee, such retiring Trustee shall, upon payment of all sums owed to it, execute and deliver an instrument transferring to such successor Trustee all the rights, powers and trusts of the retiring Trustee and shall duly assign, transfer and deliver to such successor Trustee all property and money held by such retiring Trustee hereunder, subject nevertheless to its lien provided for in Section 907.
(b) In case of the appointment hereunder of a successor Trustee with respect to the Securities of one or more (but not all) series, the Company, the retiring Trustee and each successor Trustee with respect to the Securities of one or more series shall execute and deliver an indenture supplemental hereto wherein each successor Trustee shall accept such appointment and which (1) shall contain such provisions as shall be necessary or desirable to transfer and confirm to, and to vest in, each successor Trustee all the rights, powers, trusts and duties of the retiring Trustee with respect to the Securities of that or those series to which the appointment of such successor Trustee relates, (2) if the retiring Trustee is not retiring with respect to all Securities, shall contain such provisions as shall be deemed necessary or desirable to confirm that all the rights, powers, trusts and duties of the retiring Trustee with respect to the Securities of that or those series as to which the retiring Trustee is not retiring shall continue to be vested in the retiring Trustee and (3) shall add to or change any of the provisions of this Indenture as shall be necessary to provide for or facilitate the administration of the trusts hereunder by more than one Trustee, it being understood that nothing herein or in such supplemental indenture shall constitute such Trustees co-trustees of the same trust and that each such Trustee shall be trustee of a trust or trusts hereunder separate and apart from any trust or trusts hereunder administered by any other such Trustee; and upon the execution and delivery of such supplemental indenture the resignation or removal of the retiring Trustee shall become effective to the extent provided therein and each such successor Trustee, without any further act, deed or conveyance, shall become vested with all the rights, powers, trusts and duties of the retiring Trustee with respect to the Securities of that or those series to which the appointment of such successor Trustee relates; but, on request of the Company or any
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successor Trustee, such retiring Trustee, upon payment of all sums owed to it, shall duly assign, transfer and deliver to such successor Trustee all property and money held by such retiring Trustee hereunder with respect to the Securities of that or those series to which the appointment of such successor Trustee relates, subject nevertheless to its lien provided for in Section 907.
(c) Upon request of any such successor Trustee, the Company shall execute any instruments which fully vest in and confirm to such successor Trustee all such rights, powers and trusts referred to in Subsection (a) or (b) of this Section, as the case may be.
(d) No successor Trustee shall accept its appointment unless at the time of such acceptance such successor Trustee shall be qualified and eligible under this Article.
SECTION 912. Merger, Conversion, Consolidation or Succession to Business.
Any Person into which the Trustee may be merged or converted or with which it may be consolidated, or any Person resulting from any merger, conversion or consolidation to which the Trustee shall be a party, or any Person succeeding to all or substantially all the corporate trust business of the Trustee, shall be the successor of the Trustee hereunder, provided such Person shall be otherwise qualified and eligible under this Article, without the execution or filing of any paper or any further act on the part of any of the parties hereto. In case any Securities shall have been authenticated, but not delivered, by the Trustee then in office, any successor by merger, conversion or consolidation to such authenticating Trustee may adopt such authentication and deliver the Securities so authenticated with the same effect as if such successor Trustee had itself authenticated such Securities.
SECTION 913. Preferential Collection of Claims Against Company.
If the Trustee shall be or become a creditor of the Company or any other obligor upon the Securities (other than by reason of a relationship described in Section 311(b) of the Trust Indenture Act), the Trustee shall be subject to any and all applicable provisions of the Trust Indenture Act regarding the collection of claims against the Company or such other obligor. For purposes of Section 311(b) of the Trust Indenture Act:
(a) the term “cash transaction” means any transaction in which full payment for goods or securities sold is made within seven days after delivery of the goods or securities in currency or in checks or other orders drawn upon banks or bankers and payable upon demand;
(b) the term “self-liquidating paper” means any draft, bill of exchange, acceptance or obligation which is made, drawn, negotiated or incurred by the Company for the purpose of financing the purchase, processing, manufacturing, shipment, storage or sale of goods, wares or merchandise and which is secured by documents evidencing title to, possession of, or a lien upon, the goods, wares or merchandise or the receivables or proceeds arising from the sale of the goods, wares or merchandise previously constituting the security, provided the security is received by the Trustee simultaneously with the creation of the creditor relationship with the Company arising from the making, drawing, negotiating or incurring of the draft, bill of exchange, acceptance or obligation.
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SECTION 914. Co-trustees and Separate Trustees.
At any time or times, for the purpose of meeting the legal requirements of any applicable jurisdiction, the Company and the Trustee shall have power to appoint, and, upon the written request of the Trustee or of the Holders of at least 33% in principal amount of the Securities then Outstanding, the Company shall for such purpose join with the Trustee in the execution and delivery of all instruments and agreements necessary or proper to appoint, one or more Persons approved by the Trustee either to act as co-trustee, jointly with the Trustee, or to act as separate trustee, in either case with such powers as may be provided in the instrument of appointment, and to vest in such Person or Persons, in the capacity aforesaid, any property, title, right or power deemed necessary or desirable, subject to the other provisions of this Section. If the Company does not join in such appointment within 15 days after the receipt by it of a request so to do, or if an Event of Default shall have occurred and be continuing, the Trustee alone shall have power to make such appointment.
Should any written instrument or instruments from the Company be required by any co-trustee or separate trustee so appointed to more fully confirm to such co-trustee or separate trustee such property, title, right or power, any and all such instruments shall, on request, be executed, acknowledged and delivered by the Company.
Every co-trustee or separate trustee shall, to the extent permitted by law, but to such extent only, be appointed subject to the following conditions:
(a) the Securities shall be authenticated and delivered, and all rights, powers, duties and obligations hereunder in respect of the custody of securities, cash and other personal property held by, or required to be deposited or pledged with, the Trustee hereunder, shall be exercised solely, by the Trustee;
(b) the rights, powers, duties and obligations hereby conferred or imposed upon the Trustee in respect of any property covered by such appointment shall be conferred or imposed upon and exercised or performed either by the Trustee or by the Trustee and such co-trustee or separate trustee jointly, as shall be provided in the instrument appointing such co-trustee or separate trustee, except to the extent that under any law of any jurisdiction in which any particular act is to be performed, the Trustee shall be incompetent or unqualified to perform such act, in which event such rights, powers, duties and obligations shall be exercised and performed by such co-trustee or separate trustee;
(c) the Trustee at any time, by an instrument in writing executed by it, with the concurrence of the Company, may accept the resignation of or remove any co-trustee or separate trustee appointed under this Section, and, if an Event of Default shall have occurred and be continuing, the Trustee shall have power to accept the resignation of, or remove, any such co-trustee or separate trustee without the concurrence of the Company. Upon the written request of the Trustee, the Company shall join with the Trustee in the execution and delivery of all instruments and agreements necessary or proper to effectuate such resignation or removal. A successor to any co-trustee or separate trustee so resigned or removed may be appointed in the manner provided in this Section;
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(d) no co-trustee or separate trustee hereunder shall be personally liable by reason of any act or omission of the Trustee, or any other such trustee hereunder; and the Trustee shall not be personally liable by reason of any act or omission of any such co-trustee or separate trustee; and
(e) any Act of Holders delivered to the Trustee shall be deemed to have been delivered to each such co-trustee and separate trustee.
SECTION 915. Appointment of Authenticating Agent.
The Trustee may appoint an Authenticating Agent or Agents with respect to the Securities of one or more series, or Tranche thereof, which shall be authorized to act on behalf of the Trustee to authenticate Securities of such series or Tranche issued upon original issuance and upon exchange, registration of transfer or partial redemption thereof or pursuant to Section 306, and Securities so authenticated shall be entitled to the benefits of this Indenture and shall be valid and obligatory for all purposes as if authenticated by the Trustee hereunder. Wherever reference is made in this Indenture to the authentication and delivery of Securities by the Trustee or the Trustee’s certificate of authentication, such reference shall be deemed to include authentication and delivery on behalf of the Trustee by an Authenticating Agent and a certificate of authentication executed on behalf of the Trustee by an Authenticating Agent. Each Authenticating Agent shall be acceptable to the Company and shall at all times be a corporation organized and doing business under the laws of the United States, any State or territory thereof or the District of Columbia, authorized under such laws to act as Authenticating Agent, having a combined capital and surplus of not less than $50,000,000 and subject to supervision or examination by Federal or State authority. If such Authenticating Agent publishes reports of condition at least annually, pursuant to law or to the requirements of said supervising or examining authority, then for the purposes of this Section, the combined capital and surplus of such Authenticating Agent shall be deemed to be its combined capital and surplus as set forth in its most recent report of condition so published. If at any time an Authenticating Agent shall cease to be eligible in accordance with the provisions of this Section, such Authenticating Agent shall resign immediately in the manner and with the effect specified in this Section.
Any corporation into which an Authenticating Agent may be merged or converted or with which it may be consolidated, or any corporation resulting from any merger, conversion or consolidation to which such Authenticating Agent shall be a party, or any corporation succeeding to the corporate agency or corporate trust business of an Authenticating Agent, shall continue to be an Authenticating Agent, provided such corporation shall be otherwise eligible under this Section, without the execution or filing of any paper or any further act on the part of the Trustee or the Authenticating Agent.
An Authenticating Agent may resign at any time by giving written notice thereof to the Trustee and to the Company. The Trustee may at any time terminate the agency of an Authenticating Agent by giving written notice thereof to such Authenticating Agent and to the Company. Upon receiving such a notice of resignation or upon such a termination, or in case at any time such Authenticating Agent shall cease to be eligible in accordance with the provisions of this Section, the Trustee may appoint a successor Authenticating Agent which shall be acceptable to the Company. Any successor Authenticating Agent upon acceptance of its
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appointment hereunder shall become vested with all the rights, powers and duties of its predecessor hereunder, with like effect as if originally named as an Authenticating Agent. No successor Authenticating Agent shall be appointed unless eligible under the provisions of this Section.
The Trustee agrees to pay to each Authenticating Agent from time to time reasonable compensation for its services under this Section, and the Trustee shall be entitled to be reimbursed for such payments, in accordance with, and subject to the provisions of, Section 907.
The provisions of Sections 308, 904 and 905 shall be applicable to each Authenticating Agent.
If an appointment with respect to the Securities of one or more series shall be made pursuant to this Section, the Securities of such series may have endorsed thereon, in addition to the Trustee’s certificate of authentication, an alternate certificate of authentication substantially in the following form:
This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.
THE BANK OF NEW YORK | ||
| By |
| |
As Authenticating Agent | ||
| By |
| |
| Authorized Signatory | ||
If all of the Securities of a series may not be originally issued at one time, and if the Trustee does not have an office capable of authenticating Securities upon original issuance located in a Place of Payment where the Company wishes to have Securities of such series authenticated upon original issuance, the Trustee, if so requested by the Company in writing (which writing need not comply with Section 102 and need not be accompanied by an Opinion of Counsel), shall appoint, in accordance with this Section and in accordance with such procedures as shall be acceptable to the Trustee, an Authenticating Agent having an office in a Place of Payment designated by the Company with respect to such series of Securities.
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ARTICLE TEN
Holders’ Lists and Reports by Trustee and Company
SECTION 1001. Lists of Holders.
Semiannually, not later than June 1 and December 1 in each year, commencing June 1, 2005, and at such other times as the Trustee may request in writing, the Company shall furnish or cause to be furnished to the Trustee information as to the names and addresses of the Holders, and the Trustee shall preserve such information and similar information received by it in any other capacity and afford to the Holders access to information so preserved by it, all to such extent, if any, and in such manner as shall be required by the Trust Indenture Act; provided, however, that no such list need be furnished so long as the Trustee shall be the Security Registrar.
SECTION 1002. Reports by Trustee and Company.
Not later than November 1 in each year, commencing with the year 2005, the Trustee shall transmit to the Holders, the Commission and each securities exchange upon which any Securities are listed, a report, dated as of the next preceding September 15, with respect to any events and other matters described in Section 313(a) of the Trust Indenture Act, in such manner and to the extent required by the Trust Indenture Act. The Trustee shall transmit to the Holders, the Commission and each securities exchange upon which any Securities are listed, and the Company shall file with the Trustee (within 30 days after filing with the Commission in the case of reports which pursuant to the Trust Indenture Act must be filed with the Commission and furnished to the Trustee) and transmit to the Holders, such other information, reports and other documents, if any, at such times and in such manner, as shall be required by the Trust Indenture Act. The Company shall notify the Trustee of the listing of any Securities on any securities exchange and of any delisting thereof.
Delivery of such reports, information and documents filed with the Commission pursuant to the Securities Exchange Act of 1934, as amended, to the Trustee is for informational purposes only, and the Trustee’s receipt of such shall not constitute notice or constructive notice of any information contained therein or determinable from information contained therein, including the Company’s compliance with any of its covenants hereunder (as to which the Trustee is entitled to rely exclusively on Officer’s Certificates).
ARTICLE ELEVEN
Consolidation, Merger, Conveyance or Other Transfer
SECTION 1101. Company May Consolidate, etc., Only on Certain Terms.
The Company shall not consolidate with or merge into any other corporation, in each case in a transaction in which it is not the successor corporation, or convey, transfer or lease its properties and assets as an entirety or substantially as an entirety to any Person, unless
(a) the corporation formed by such consolidation or into which the Company is merged, or the corporation that acquires by conveyance or transfer, or which leases, the properties and assets of the Company as an entirety or substantially as an entirety, shall be a corporation organized and validly existing under the laws of the United States, any State thereof or the District of Columbia, and shall expressly assume, by an indenture supplemental hereto, executed and delivered to the Trustee, in form satisfactory to the Trustee, the due and punctual payment of the principal of and premium, if any, and interest, if any, on all Outstanding Securities and the performance of every covenant of this Indenture on the part of the Company to be performed or observed;
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(b) immediately after giving effect to such transaction, no Event of Default, and no event which, after notice or lapse of time or both, would become an Event of Default, shall have occurred and be continuing; and
(c) the Company shall have delivered to the Trustee an Officer’s Certificate and an Opinion of Counsel, each stating that such consolidation, merger, conveyance or other transfer or lease and such indenture supplemental hereto comply with this Article and that all conditions precedent herein provided for relating to such transactions have been complied with.
SECTION 1102. Successor Corporation Substituted.
Upon any consolidation by the Company with or merger by the Company into any other corporation, or any conveyance or other transfer or lease of the properties and assets of the Company as an entirety or substantially as an entirety in accordance with Section 1101, the successor corporation formed by such consolidation or into which the Company is merged or the Person to which such conveyance, or other transfer or lease is made shall succeed to, and be substituted for, and may exercise every right and power of, the Company under this Indenture with the same effect as if such successor Person had been named as the Company herein, and thereafter, except in the case of a lease, the predecessor Person shall be relieved of and released from all obligations and covenants under this Indenture and the Securities Outstanding hereunder (unless the Company shall have delivered to the Trustee an instrument waiving such relief and release), and the Trustee shall acknowledge in writing that the Company has been so relieved and released.
SECTION 1103. Limitations.
For purposes of clarification and not in limitation of the provisions of Section 1101, unless otherwise provided in a supplemental indenture or Officer’s Certificate, nothing in this Indenture shall be deemed to prevent or restrict:
(a) any consolidation or merger after the consummation of which the Company would be the surviving or resulting corporation, or
(b) any conveyance or other transfer, or lease of any part of the properties of the Company which does not constitute the entirety, or substantially the entirety, thereof, or
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(c) the approval by the Company of, or the consent by the Company to, any consolidation or merger of any direct or indirect subsidiary or affiliate of the Company, or any conveyance, transfer or lease by any such subsidiary or affiliate of any of its assets.
ARTICLE TWELVE
Supplemental Indentures
SECTION 1201. Supplemental Indentures Without Consent of Holders.
Without the consent of any Holders, the Company and the Trustee, at any time and from time to time, may enter into one or more indentures supplemental hereto, in form satisfactory to the Trustee, for any of the following purposes:
(a) to evidence the succession of another Person to the Company and the assumption by any such successor of the covenants of the Company herein and in the Securities, all as provided in Article Eleven; or
(b) to add one or more covenants of the Company or other provisions for the benefit of all Holders or for the benefit of the Holders of, or to remain in effect only so long as there shall be Outstanding, Securities of one or more specified series, or one or more specified Tranches thereof, or to surrender any right or power herein conferred upon the Company; or
(c) to add any additional Events of Default with respect to all or any series of Securities Outstanding hereunder; or
(d) to change or eliminate any provision of this Indenture or to add any new provision to this Indenture; provided, however, that if such change, elimination or addition shall adversely affect the interests of the Holders of Securities of any series or Tranche Outstanding on the date of such indenture supplemental hereto in any material respect, such change, elimination or addition shall become effective with respect to such series or Tranche only pursuant to the provisions of Section 1202 hereof or when no Security of such series or Tranche remains Outstanding; or
(e) to provide collateral security for all but not part of the Securities; or
(f) to establish the form or terms of Securities of any series or Tranche as contemplated by Sections 201 and 301; or
(g) to provide for the authentication and delivery of bearer securities and coupons appertaining thereto representing interest, if any, thereon and for the procedures for the registration, exchange and replacement thereof and for the giving of notice to, and the solicitation of the vote or consent of, the holders thereof, and for any and all other matters incidental thereto; or
(h) to evidence and provide for the acceptance of appointment hereunder by a separate or successor Trustee or co-trustee with respect to the Securities of one or more
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series and to add to or change any of the provisions of this Indenture as shall be necessary to provide for or facilitate the administration of the trusts hereunder by more than one Trustee, pursuant to the requirements of Section 911(b); or
(i) to provide for the procedures required to permit the Company to utilize, at its option, a noncertificated system of registration for all, or any series or Tranche of, the Securities; or
(j) to change any place or places where (1) the principal of and premium, if any, and interest, if any, on all or any series of Securities, or any Tranche thereof, shall be payable, (2) all or any series of Securities, or any Tranche thereof, may be surrendered for registration of transfer, (3) all or any series of Securities, or any Tranche thereof, may be surrendered for exchange and (4) notices and demands to or upon the Company in respect of all or any series of Securities, or any Tranche thereof, and this Indenture may be served; or
(k) to cure any ambiguity, to correct or supplement any provision herein which may be defective or inconsistent with any other provision herein, or to make any other changes to the provisions hereof or to add other provisions with respect to matters or questions arising under this Indenture, provided that such other changes or additions shall not adversely affect the interests of the Holders of Securities of any series or Tranche in any material respect.
Without limiting the generality of the foregoing, if the Trust Indenture Act as in effect at the date of the execution and delivery of this Indenture or at any time thereafter shall be amended and
(x) if any such amendment shall require one or more changes to any provisions hereof or the inclusion herein of any additional provisions, or shall by operation of law be deemed to effect such changes or incorporate such provisions by reference or otherwise, this Indenture shall be deemed to have been amended so as to conform to such amendment to the Trust Indenture Act, and the Company and the Trustee may, without the consent of any Holders, enter into an indenture supplemental hereto to effect or evidence such changes or additional provisions; or
(y) if any such amendment shall permit one or more changes to, or the elimination of, any provisions hereof which, at the date of the execution and delivery hereof or at any time thereafter, are required by the Trust Indenture Act to be contained herein, this Indenture shall be deemed to have been amended to effect such changes or elimination, and the Company and the Trustee may, without the consent of any Holders, enter into an indenture supplemental hereto to evidence such amendment hereof.
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SECTION 1202. Supplemental Indentures With Consent of Holders.
Subject to the provisions of Section 1201, with the consent of the Holders of a majority in aggregate principal amount of the Securities of all series then Outstanding under this Indenture, considered as one class, by Act of said Holders delivered to the Company and the Trustee, the Company, when authorized by a Board Resolution, and the Trustee may enter into an indenture or indentures supplemental hereto for the purpose of adding any provisions to, or changing in any manner or eliminating any of the provisions of, this Indenture or modifying in any manner the rights of the Holders of Securities of such series under the Indenture; provided, however, that if there shall be Securities of more than one series Outstanding hereunder and if a proposed supplemental indenture shall directly affect the rights of the Holders of Securities of one or more, but less than all, of such series, then the consent only of the Holders of a majority in aggregate principal amount of the Outstanding Securities of all series so directly affected, considered as one class, shall be required; and provided, further, that if the Securities of any series shall have been issued in more than one Tranche and if the proposed supplemental indenture shall directly affect the rights of the Holders of Securities of one or more, but less than all, of such Tranches, then the consent only of the Holders of a majority in aggregate principal amount of the Outstanding Securities of all Tranches so directly affected, considered as one class, shall be required; and provided, further, that no such supplemental indenture shall:
(a) change the Stated Maturity of the principal of, or any installment of principal of or interest on, any Security (other than pursuant to the terms hereof), or reduce the principal amount thereof or the rate of interest thereon (or the amount of any installment of interest thereon) or change the method of calculating such rate or reduce any premium payable upon the redemption thereof, or reduce the amount of the principal of a Discount Security that would be due and payable upon a declaration of acceleration of the Maturity thereof pursuant to Section 802, or change the coin or currency (or other property), in which any Security or any premium or the interest thereon is payable, or impair the right to institute suit for the enforcement of any such payment on or after the Stated Maturity of any Security (or, in the case of redemption, on or after the Redemption Date), without, in any such case, the consent of the Holder of such Security, or
(b) reduce the percentage in principal amount of the Outstanding Securities of any series, or any Tranche thereof, the consent of the Holders of which is required for any such supplemental indenture, or the consent of the Holders of which is required for any waiver of compliance with any provision of this Indenture or of any default hereunder and its consequences, or reduce the requirements of Section 1304 for quorum or voting, without, in any such case, the consent of the Holders of each Outstanding Security of such series or Tranche, or
(c) modify any of the provisions of this Section, Section 607 or Section 813 with respect to the Securities of any series, or any Tranche thereof, except to increase the percentages in principal amount referred to in this Section or such other Sections or to provide that other provisions of this Indenture cannot be modified or waived without the consent of the Holder of each Outstanding Security affected thereby; provided, however, that this clause shall not be deemed to require the consent of any Holder with respect to changes in the references to “the Trustee” and concomitant changes in this Section, or the deletion of this proviso, in accordance with the requirements of Sections 911(b), 914 and 1201(h).
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A supplemental indenture which changes or eliminates any covenant or other provision of this Indenture which has expressly been included solely for the benefit of one or more particular series of Securities, or one or more Tranches thereof, or which modifies the rights of the Holders of Securities of such series with respect to such covenant or other provision, shall be deemed not to affect the rights under this Indenture of the Holders of Securities of any other series or Tranche.
It shall not be necessary for any Act of Holders under this Section to approve the particular form of any proposed supplemental indenture, but it shall be sufficient if such Act shall approve the substance thereof. A waiver by a Holder of such Holder’s right to consent under this Section shall be deemed to be a consent of such Holder.
Anything in this Indenture to the contrary notwithstanding, if the Officer’s Certificate, supplemental indenture or Board Resolution, as the case may be, establishing the Securities of any series or Tranche shall provide that the Company may make certain specified additions, changes or eliminations to or from the Indenture which shall be specified in such Officer’s Certificate, supplemental indenture or Board Resolution establishing such series or Tranche, (a) the Holders of Securities of such series or Tranche shall be deemed to have consented to a supplemental indenture containing such additions, changes or eliminations to or from the Indenture which shall be specified in such Officer’s Certificate, supplemental indenture or Board Resolution establishing such series or Tranche, (b) no Act of such Holders shall be required to evidence such consent and (c) such consent may be counted in the determination of whether or not the Holders of the requisite principal amount of Securities shall have consented to such supplemental indenture.
SECTION 1203. Execution of Supplemental Indentures.
In executing, or accepting the additional trusts created by, any supplemental indenture permitted by this Article or the modifications thereby of the trusts created by this Indenture, the Trustee shall be entitled to receive, and (subject to Section 901) shall be fully protected in relying upon, an Opinion of Counsel stating that the execution of such supplemental indenture is authorized or permitted by this Indenture. The Trustee may, but shall not be obligated to, enter into any such supplemental indenture which affects the Trustee’s own rights, duties, immunities or liabilities under this Indenture or otherwise.
SECTION 1204. Effect of Supplemental Indentures.
Upon the execution of any supplemental indenture under this Article, this Indenture shall be modified in accordance therewith, and such supplemental indenture shall form a part of this Indenture for all purposes; and every Holder of Securities theretofore or thereafter authenticated and delivered hereunder shall be bound thereby. Any supplemental indenture permitted by this Article may restate this Indenture in its entirety, and, upon the execution and delivery thereof, any such restatement shall supersede this Indenture as theretofore in effect for all purposes.
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SECTION 1205. Conformity With Trust Indenture Act.
Every supplemental indenture executed pursuant to this Article shall conform to the requirements of the Trust Indenture Act as then in effect, if applicable.
SECTION 1206. Reference in Securities to Supplemental Indentures.
Securities of any series, or any Tranche thereof, authenticated and delivered after the execution of any supplemental indenture pursuant to this Article may, and shall if required by the Trustee, bear a notation in form approved by the Trustee as to any matter provided for in such supplemental indenture. If the Company shall so determine, new Securities of any series, or any Tranche thereof, so modified as to conform, in the opinion of the Trustee and the Company, to any such supplemental indenture may be prepared and executed by the Company and authenticated and delivered by the Trustee in exchange for Outstanding Securities of such series or Tranche.
SECTION 1207. Modification Without Supplemental Indenture.
If the terms of any particular series of Securities shall have been established in a Board Resolution or an Officer’s Certificate as contemplated by Section 301, and not in an indenture supplemental hereto, additions to, changes in or the elimination of any of such terms may be effected by means of a supplemental Board Resolution or Officer’s Certificate, as the case may be, delivered to, and accepted by, the Trustee; provided, however, that such supplemental Board Resolution or Officer’s Certificate shall not be accepted by the Trustee or otherwise be effective unless all conditions set forth in this Indenture which would be required to be satisfied if such additions, changes or elimination were contained in a supplemental indenture shall have been appropriately satisfied. Upon the acceptance thereof by the Trustee, any such supplemental Board Resolution or Officer’s Certificate shall be deemed to be a “supplemental indenture” for purposes of Sections 1204 and 1206.
ARTICLE THIRTEEN
Meetings of Holders; Action Without Meeting
SECTION 1301. Purposes for Which Meetings May Be Called.
A meeting of Holders of Securities of one or more, or all, series, or any Tranche or Tranches thereof, may be called at any time and from time to time pursuant to this Article to make, give or take any request, demand, authorization, direction, notice, consent, waiver or other action provided by this Indenture to be made, given or taken by Holders of Securities of such series or Tranches.
SECTION 1302. Call, Notice and Place of Meetings.
(a) The Trustee may at any time call a meeting of Holders of Securities of one or more, or all, series, or any Tranche or Tranches thereof, for any purpose specified in Section 1301, to be held at such time and at such place in the Borough of Manhattan, The City of New York, as the Trustee shall determine, or, with the approval of the Company, at
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any other place. Notice of every such meeting, setting forth the time and the place of such meeting and in general terms the action proposed to be taken at such meeting, shall be given, in the manner provided in Section 106, not less than 21 nor more than 180 days prior to the date fixed for the meeting.
(b) If the Trustee shall have been requested to call a meeting of the Holders of Securities of one or more, or all, series, or any Tranche or Tranches thereof, by the Company or by the Holders of 33% in aggregate principal amount of all of such series and Tranches, considered as one class, for any purpose specified in Section 1301, by written request setting forth in reasonable detail the action proposed to be taken at the meeting, and the Trustee shall not have given the notice of such meeting within 21 days after receipt of such request or shall not thereafter proceed to cause the meeting to be held as provided herein, then the Company or the Holders of Securities of such series and Tranches in the amount above specified, as the case may be, may determine the time and the place in the Borough of Manhattan, The City of New York, or in such other place as shall be determined or approved by the Company, for such meeting and may call such meeting for such purposes by giving notice thereof as provided in Subsection (a) of this Section.
(c) Any meeting of Holders of Securities of one or more, or all, series, or any Tranche or Tranches thereof, shall be valid without notice if the Holders of all Outstanding Securities of such series or Tranches are present in person or by proxy and if representatives of the Company and the Trustee are present, or if notice is waived in writing before or after the meeting by the Holders of all Outstanding Securities of such series, or any Tranche or Tranches thereof, or by such of them as are not present at the meeting in person or by proxy, and by the Company and the Trustee.
SECTION 1303. Persons Entitled to Vote at Meetings.
To be entitled to vote at any meeting of Holders of Securities of one or more, or all, series, or any Tranche or Tranches thereof, a Person shall be (a) a Holder of one or more Outstanding Securities of such series or Tranches, or (b) a Person appointed by an instrument in writing as proxy for a Holder or Holders of one or more Outstanding Securities of such series or Tranches by such Holder or Holders. The only Persons who shall be entitled to attend any meeting of Holders of Securities of any series or Tranche shall be the Persons entitled to vote at such meeting and their counsel, any representatives of the Trustee and its counsel and any representatives of the Company and its counsel.
SECTION 1304. Quorum; Action.
The Persons entitled to vote a majority in aggregate principal amount of the Outstanding Securities of the series and Tranches with respect to which a meeting shall have been called as hereinbefore provided, considered as one class, shall constitute a quorum for a meeting of Holders of Securities of such series and Tranches; provided, however, that if any action is to be taken at such meeting which this Indenture expressly provides may be taken by the Holders of a specified percentage, which is less than a majority, in principal amount of the Outstanding Securities of such series and Tranches, considered as one class, the Persons entitled to vote such specified percentage in principal amount of the Outstanding Securities of such series
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and Tranches, considered as one class, shall constitute a quorum. In the absence of a quorum within one hour of the time appointed for any such meeting, the meeting shall, if convened at the request of Holders of Securities of such series and Tranches, be dissolved. In any other case the meeting may be adjourned for such period as may be determined by the chairman of the meeting prior to the adjournment of such meeting. In the absence of a quorum at any such adjourned meeting, such adjourned meeting may be further adjourned for such period as may be determined by the chairman of the meeting prior to the adjournment of such adjourned meeting. Except as provided by Section 1305(e), notice of the reconvening of any meeting adjourned for more than 30 days shall be given as provided in Section 1302(a) not less than 10 days prior to the date on which the meeting is scheduled to be reconvened. Notice of the reconvening of an adjourned meeting shall state expressly the percentage, as provided above, of the principal amount of the Outstanding Securities of such series and Tranches which shall constitute a quorum.
Except as limited by Section 1202, any resolution presented to a meeting or adjourned meeting duly reconvened at which a quorum is present as aforesaid may be adopted only by the affirmative vote of the Holders of a majority in aggregate principal amount of the Outstanding Securities of the series and Tranches with respect to which such meeting shall have been called, considered as one class; provided, however, that, except as so limited, any resolution with respect to any action which this Indenture expressly provides may be taken by the Holders of a specified percentage, which is less than a majority, in principal amount of the Outstanding Securities of such series and Tranches, considered as one class, may be adopted at a meeting or an adjourned meeting duly reconvened and at which a quorum is present as aforesaid by the affirmative vote of the Holders of such specified percentage in principal amount of the Outstanding Securities of such series and Tranches, considered as one class.
Any resolution passed or decision taken at any meeting of Holders of Securities duly held in accordance with this Section shall be binding on all the Holders of Securities of the series and Tranches with respect to which such meeting shall have been held, whether or not present or represented at the meeting.
SECTION 1305. Attendance at Meetings; Determination of Voting Rights;
Conduct and Adjournment of Meetings.
(a) Attendance at meetings of Holders of Securities may be in person or by proxy; and, to the extent permitted by law, any such proxy shall remain in effect and be binding upon any future Holder of the Securities with respect to which it was given unless and until specifically revoked by the Holder or future Holder of such Securities before being voted.
(b) Notwithstanding any other provisions of this Indenture, the Trustee may make such reasonable regulations as it may deem advisable for any meeting of Holders of Securities in regard to proof of the holding of such Securities and of the appointment of proxies and in regard to the appointment and duties of inspectors of votes, the submission and examination of proxies, certificates and other evidence of the right to vote, and such other matters concerning the conduct of the meeting as it shall deem appropriate. Except as otherwise permitted or required by any such regulations, the holding of Securities shall be proved in the manner specified in Section 104 and the appointment of any proxy shall
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be proved in the manner specified in Section 104. Such regulations may provide that written instruments appointing proxies, regular on their face, may be presumed valid and genuine without the proof specified in Section 104 or other proof.
(c) The Trustee shall, by an instrument in writing, appoint a temporary chairman of the meeting, unless the meeting shall have been called by the Company or by Holders as provided in Section 1302(b), in which case the Company or the Holders of Securities of the series and Tranches calling the meeting, as the case may be, shall in like manner appoint a temporary chairman. A permanent chairman and a permanent secretary of the meeting shall be elected by vote of the Persons entitled to vote a majority in aggregate principal amount of the Outstanding Securities of all series and Tranches represented at the meeting, considered as one class.
(d) At any meeting each Holder or proxy shall be entitled to one vote for each $1 principal amount of Securities held or represented by him; provided, however, that no vote shall be cast or counted at any meeting in respect of any Security challenged as not Outstanding and ruled by the chairman of the meeting to be not Outstanding. The chairman of the meeting shall have no right to vote, except as a Holder of a Security or proxy.
(e) Any meeting duly called pursuant to Section 1302 at which a quorum is present may be adjourned from time to time by Persons entitled to vote a majority in aggregate principal amount of the Outstanding Securities of all series and Tranches represented at the meeting, considered as one class; and the meeting may be held as so adjourned without further notice.
SECTION 1306. Counting Votes and Recording Action of Meetings.
The vote upon any resolution submitted to any meeting of Holders shall be by written ballots on which shall be subscribed the signatures of the Holders or of their representatives by proxy and the principal amounts and serial numbers of the Outstanding Securities, of the series and Tranches with respect to which the meeting shall have been called, held or represented by them. The permanent chairman of the meeting shall appoint two inspectors of votes who shall count all votes cast at the meeting for or against any resolution and who shall make and file with the secretary of the meeting their verified written reports of all votes cast at the meeting. A record of the proceedings of each meeting of Holders shall be prepared by the secretary of the meeting and there shall be attached to said record the original reports of the inspectors of votes on any vote by ballot taken thereat and affidavits by one or more persons having knowledge of the facts setting forth a copy of the notice of the meeting and showing that said notice was given as provided in Section 1302 and, if applicable, Section 1304. Each copy shall be signed and verified by the affidavits of the permanent chairman and secretary of the meeting and one such copy shall be delivered to the Company, and another to the Trustee to be preserved by the Trustee, the latter to have attached thereto the ballots voted at the meeting. Any record so signed and verified shall be conclusive evidence of the matters therein stated.
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SECTION 1307. Action Without Meeting.
In lieu of a vote of Holders at a meeting as hereinbefore contemplated in this Article, any request, demand, authorization, direction, notice, consent, waiver or other action may be made, given or taken by Holders by written instruments as provided in Section 104.
ARTICLE FOURTEEN
Immunity of Incorporators, Shareholders, Members, Officers, Managers and Directors
SECTION 1401. Liability Solely Corporate.
No recourse shall be had for the payment of the principal of or premium, if any, or interest, if any, on any Securities or any part thereof, or for any claim based thereon or otherwise in respect thereof, or of the indebtedness represented thereby, or upon any obligation, covenant or agreement under this Indenture, against any incorporator, shareholder, member, limited partner, officer, manager or director, as such, past, present or future of the Company or of any predecessor or successor of the Company (either directly or through the Company or a predecessor or successor of the Company), whether by virtue of any constitutional provision, statute or rule of law, or by the enforcement of any assessment or penalty or otherwise; it being expressly agreed and understood that this Indenture and all the Securities are solely corporate obligations, and that no personal liability whatsoever shall attach to, or be incurred by, any incorporator, shareholder, member, limited partner, officer, manager or director, past, present or future, of the Company or of any predecessor or successor of the Company, either directly or indirectly through the Company or any predecessor or successor of the Company, because of the indebtedness hereby authorized or under or by reason of any of the obligations, covenants or agreements contained in this Indenture or in any of the Securities or to be implied herefrom or therefrom, and that any such personal liability is hereby expressly waived and released as a condition of, and as part of the consideration for, the execution of this Indenture and the issuance of the Securities.
ARTICLE FIFTEEN
Series Q Notes
SECTION 1501. Designation of Series Q Notes.
There is hereby created a series of Securities designated “6.50% Series Q Senior Notes due November 15, 2024” (herein sometimes referred to as “Series Q Notes”). The form and terms of the Series Q Notes shall be established in an Officer’s Certificate pursuant to Sections 201 and 301.
This instrument may be executed in any number of counterparts, each of which so executed shall be deemed to be an original, but all such counterparts shall together constitute but one and the same instrument.
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IN WITNESS WHEREOF, the parties hereto have caused this Indenture to be duly executed, all as of the day and year first above written.
| TXU CORP. | ||
| By: | /s/ ANTHONY R. HORTON | |
Name: Anthony Horton | ||
Title: Senior Vice President and Treasurer | ||
| THE BANK OF NEW YORK, Trustee | ||
| By: | /s/ REMO J. REALE | |
Name: Remo J. Reale | ||
Title: Vice President | ||
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Exhibit 4(aaa)
THIS DEED OF TRUST IS, AMONG OTHER THINGS, A FINANCING STATEMENT UNDER THE UNIFORM COMMERCIAL CODE COVERING MINERALS, TIMBER, AS-EXTRACTED COLLATERAL AND THE LIKE, ACCOUNTS RESULTING FROM THE SALE OF MINERALS, TIMBER, AS-EXTRACTED COLLATERAL AND THE LIKE, AND GOOD WHICH ARE, OR ARE TO BECOME, FIXTURES ON THE REAL/IMMOVABLE PROPERTY DESCRIBED IN EXHIBITS A, B AND C ATTACHED HERETO. THIS DEED OF TRUST IS TO BE RECORDED IN THE REAL ESTATE RECORDS AND AS A FIXTURES, TIMBER AND AS-EXTRACTED COLLATERAL FILING OF THE COUNTY IN WHICH IS SITUATED ANY OF THE REAL PROPERTY COLLATERAL COVERED HEREBY.
NOTICE OF CONFIDENTIALITY RIGHTS: IF YOU ARE A NATURAL PERSON, YOU MAY REMOVE OR STRIKE ANY OR ALL OF THE FOLLOWING INFORMATION FROM ANY INSTRUMENT THAT TRANSFERS AN INTEREST IN REAL PROPERTY BEFORE IT IS FILED FOR RECORD IN THE PUBLIC RECORDS: YOUR SOCIAL SECURITY NUMBER OR YOUR DRIVER’S LICENSE NUMBER.
| When Recorded Return To: | TO BE RECORDED IN | |||
| ||||
| Vinson & Elkins L.L.P. | COUNTIES, TEXAS | |||
| 2001 Ross Avenue, Suite 3700 | ||||
| Dallas, TX 75201 | [NAME OF PLANT] | |||
| Attention: Jason B. Myers | ||||
| Recorder’s Use | ||||
SECOND DEED OF TRUST, ASSIGNMENT OF LEASES AND RENTS,
SECURITY AGREEMENT AND FIXTURE FILING
by
[NAME OF EFH GRANTOR], as Grantor
to
FIDELITY NATIONAL TITLE INSURANCE COMPANY, as Trustee
for the benefit of
THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., as Collateral Agent
and Initial Second Priority Representative for the benefit of the Second Lien Secured
Parties, as Beneficiary
Dated as of December , 2010
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TABLE OF CONTENTS
| Page | ||||||||
1. | DEFINITIONS | 2 | ||||||
2. | GRANT | 5 | ||||||
3. | WARRANTIES, REPRESENTATIONS AND COVENANTS | 6 | ||||||
3.1 | Title to Mortgaged Property and Lien of this Instrument; Warranties Regarding Warranty Property | 6 | ||||||
3.2 | Payment of Obligations | 6 | ||||||
3.3 | Requirements | 7 | ||||||
3.4 | Payment of Taxes and Other Impositions | 7 | ||||||
3.5 | Insurance | 7 | ||||||
3.6 | Restrictions on Liens and Encumbrances | 7 | ||||||
3.7 | Due on Sale and Other Transfer Restrictions | 7 | ||||||
3.8 | Condemnation/Eminent Domain | 8 | ||||||
3.9 | Leases | 8 | ||||||
3.10 | Further Assurances | 8 | ||||||
3.11 | Beneficiary’s Right to Perform | 8 | ||||||
4. | LIMITATION ON AMOUNT OBLIGATED; CONTRIBUTION BY OTHER PERSONS | 8 | ||||||
5. | REMEDIES | 9 | ||||||
6. | RIGHT OF BENEFICIARY TO CREDIT SALE | 11 | ||||||
7. | APPOINTMENT OF RECEIVER | 11 | ||||||
8. | EXTENSION, RELEASE, ETC | 11 | ||||||
9. | SECURITY AGREEMENT UNDER UNIFORM COMMERCIAL CODE; FIXTURE FILING | 12 | ||||||
10. | ASSIGNMENT OF RENTS | 13 | ||||||
11. | ADDITIONAL RIGHTS | 14 | ||||||
12. | NOTICES | 14 | ||||||
13. | NO ORAL MODIFICATION | 14 | ||||||
14. | PARTIAL INVALIDITY | 14 | ||||||
15. | GRANTOR’S WAIVER OF RIGHTS | 15 | ||||||
16. | REMEDIES NOT EXCLUSIVE | 15 | ||||||
17. | MULTIPLE SECURITY | 17 | ||||||
18. | SUCCESSORS AND ASSIGNS | 18 | ||||||
19. | NO WAIVERS, ETC. | 18 | ||||||
20. | GOVERNING LAW, ETC. | 19 | ||||||
21. | DUTY OF BENEFICIARY; AUTHORITY OF BENEFICIARY | 19 | ||||||
22. | LAST DOLLARS SECURED; PRIORITY | 20 | ||||||
23. | ENFORCEMENT EXPENSES; INDEMNIFICATION | 20 | ||||||
24. | RELEASE | 21 | ||||||
25. | SUBSTITUTE TRUSTEE | 21 | ||||||
26. | INDEMNIFICATION OF TRUSTEE | 22 | ||||||
27. | ACCEPTANCE BY TRUSTEE | 22 | ||||||
28. | ENTIRE AGREEMENT | 22 | ||||||
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29. | MATURITY OF OBLIGATIONS | 23 | ||||
30. | EVIDENCE OF INSURANCE | 23 | ||||
31. | FUTURE ADVANCES | 23 | ||||
32. | MULTIPLE GRANTORS | 23 | ||||
33. | ONCOR SEPARATENESS | 23 | ||||
34. | MORTGAGED LEASES | 24 |
| Exhibit A: | Description of Fee Owned Land | |
| Exhibit B: | Description of Mortgaged Leases and Mortgaged Leased Land | |
| Exhibit C: | Description of Easements and Easement Land | |
| Exhibit D: | Description of Certificates of Adjudication and Other Water Rights |
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SECOND DEED OF TRUST, ASSIGNMENT OF LEASES AND RENTS,
SECURITY AGREEMENT AND FIXTURE FILING
This Second Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing (this “Deed of Trust”) executed to be effective as of December , 2010, by[NAME OF OWNER OF PLANT AND STATE AND TYPE OF ENTITY] (“Grantor”), having an organizational identification number of and an office at c/o Texas Competitive Electric Holdings Company LLC, Energy Plaza, 1601 Bryan Street, Dallas, Texas 75201, Attention: General Counsel, to FIDELITY NATIONAL TITLE INSURANCE COMPANY, as Trustee (“Trustee”), whose address is c/o Alamo Title Insurance Company, 10010 San Pedro, Suite 440, San Antonio, Texas 78216 (Attention: Stanley Keeton), and its substitutes or successors, for the benefit of THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A. (“Beneficiary”), as Collateral Agent under and as defined in the hereinafter described Security Agreement and as Initial Second Priority Representative under and as defined in the hereinafter described Intercreditor Agreement, in each case for the benefit of the Second Lien Secured Parties, whose address is c/o Corporate Trust Division, 601 Travis Street – 16th Floor, Houston, Texas 77002 (Attention: TCEH Trustee).
RECITALS
1. TEXAS COMPETITIVE ELECTRIC HOLDINGS COMPANY LLC, a Delaware limited liability company (“TCEH”), TCEH FINANCE, INC., a Delaware corporation (“TCEH Finance”, and together with TCEH, the “Issuer”), ENERGY FUTURE COMPETITIVE HOLDINGS COMPANY, a Texas corporation (the “Parent Guarantor”), the Subsidiary Guarantors (as defined in the Indenture (as defined below)), and THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., as Trustee, have entered into the Indenture dated October 6, 2010, as supplemented by that certain First Supplemental Indenture dated as of October 20, 2010, and that certain Second Supplemental Indenture dated November 15, 2010, (as the same has or may be amended, restated, supplemented or otherwise modified, refinanced or replaced from time to time, the “Indenture”) pursuant to which certain of the Second Lien Secured Parties have severally agreed to advance funds to or purchase certain notes from Issuer (together with any such advances or purchases by any other Second Lien Secured Parties under any Additional Second Lien Agreement, the “Extensions of Credit”) upon the terms and subject to the conditions set forth therein. This Deed of Trust is being executed and delivered in accordance with Section 11.05(a) of the Indenture.
2. In addition to serving as the Collateral Agent under the Security Agreement, as Trustee under the Indenture and as Initial Second Priority Representative under the Intercreditor Agreement, Beneficiary may also serve as a Second Priority Representative for any additional Second Priority Debt Facility, under and as each of the foregoing terms are defined in the Intercreditor Agreement (as defined below).
3. Certain subsidiaries of TCEH, including Grantor, have agreed to guarantee all of Issuer’s obligations under the Indenture in accordance with the terms thereof and may guarantee Additional Second Lien Obligations to the extent permitted by the Indenture and any Additional Second Lien Agreement. Grantor is a Subsidiary Guarantor.
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4. Grantor acknowledges that it will derive substantial direct and indirect benefit from the Extensions of Credit and has agreed to secure its obligations with respect thereto pursuant to this Deed of Trust.
AGREEMENT
In consideration of the premises and to induce each present or future Second Lien Secured Party to make their respective Extensions of Credit, Grantor hereby agrees with Beneficiary, for the ratable benefit of the Second Lien Secured Parties, as follows:
| 1. | DEFINITIONS |
As used herein, the following terms shall have the following meanings:
“Additional Second Lien Agreement” has the meaning given to it in the Security Agreement.
“Additional Second Lien Obligations” has the meaning given to it in the Security Agreement.
“Excluded Property” means Excluded Property, Excluded Lease Rights (each as defined in the Security Agreement) and other personal property to the extent (and only to the extent) excluded from the grant of the security interest pursuant to the proviso at the end of Section 2(a) of the Security Agreement or excluded in the definitions of the items constituting “Collateral” under the Security Agreement.
“Intercreditor Agreement” means that certain Second Lien Intercreditor Agreement, dated as of October 6, 2010, as supplemented by that certain Representative Supplement No. 1 dated as of October 20, 2010 (as has been and may be amended, amended and restated, supplemented or otherwise modified from time to time), among Citibank, N.A., as first lien administrative agent and collateral agent, The Bank of New York Mellon Trust Company, N.A., as the Initial Second Priority Representative (as defined therein), Grantor and such other parties as may from time to time become party thereto.
“Material Adverse Effect” shall mean any circumstances or conditions affecting the business, assets, operations, properties or financial condition of the Issuer and its Subsidiaries, taken as a whole, that would, individually or in the aggregate, materially adversely affect (a) the ability of the Issuer and the Guarantors, taken as a whole, to perform their payment obligations under any Second Lien Security Documents or (b) the rights and remedies of Beneficiary and any Second Lien Secured Party under any Second Lien Security Documents.
“Mortgaged Property” means: (1) the real property described inExhibit A, together with any greater estate therein as hereafter may be acquired by Grantor (the “Land”); (2) the tenant’s or lessee’s interests (the “Leasehold Estate”) created by any lease or sublease (as amended to date and as amended, amended and restated, supplemented, renewed or otherwise modified from time to time in accordance with the provisions of this Deed of Trust, the “Mortgaged Leases”), described inExhibit B, whichExhibit B describes the properties demised under each such Mortgaged Lease (the “Mortgaged Leased Land”); (3) all buildings, structures and other
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improvements, now or at any time situated, placed or constructed upon the Land, and all of Grantor’s interests in any buildings, structures and other improvements, now or at any time situated, placed or constructed upon the Mortgaged Leased Land or the Easement Land (but in each case excluding any portion thereof (the “Unbundled Exception Portion”) conveyed to TXU Electric Delivery Company [or TXU Mining Company] in Special Warranty Deed dated effective as of January 1, 2002 conveying the Land to TXU Generation Company LP, together with any greater estate therein as hereafter may be acquired by Grantor (the “Improvements”), (4) all goods that constitute fixtures under the UCC that are installed in or attached to the Land, the Mortgaged Leased Land, the Easement Land or the Improvements (the “Fixtures”); (5) Grantor’s interest in any and all now existing or hereafter acquired easements and rights-of-way, including, without limitation, those described inExhibit C hereto (as amended to date and as amended, amended and restated, supplemented, renewed or otherwise modified from time to time in accordance with the provisions of this Deed of Trust, the “Easement Rights”), with the real property interest covered thereby, including, without limitation, those described inExhibit C being herein called the “Easement Land”); (6) Grantor’s interest in, to and under all now existing or hereafter acquired certificates of adjudication, water rights permits, water rights agreements and similar agreements, including, without limitation, those described inExhibit D (as amended to date and as amended, amended and restated, supplemented, renewed or otherwise modified from time to time in accordance with the provisions of this Deed of Trust, the “Water Rights”); (7) Grantor’s interest in, to and under all, whether now existing or hereafter acquired, leases, subleases, licenses, concessions, occupancy agreements or other agreements which grant to a Person other than Grantor a possessory interest in, or the right to use, all or any part of the Mortgaged Property, together with all related security and other deposits (as amended to date and as amended, amended and restated, supplemented, renewed or otherwise modified from time to time in accordance with the provisions of this Deed of Trust, the “Leases”); (8) Grantor’s interest in and to all of the rents, revenues, income, proceeds, profits, security and other types of deposits, and other benefits paid or payable by parties to the Leases other than Grantor for using, leasing, licensing, possessing, operating from, residing in, selling or otherwise enjoying the Mortgaged Property (in each case whether now existing or hereafter acquired, the “Rents”); (9) all rights, privileges, tenements, hereditaments, rights-of-way, easements, appendages and appurtenances appertaining to the foregoing, and all right, title and interest, if any, of Grantor in and to any streets, ways, alleys, strips or gores of land adjoining the Land, the Mortgaged Leased Land, the Easement Land or any part thereof, in each case whether now or hereafter existing; (10) Grantor’s interest in and to all timber to be cut and mineral, coal, lignite, oil and gas rights now or hereafter acquired and relating to all or any part of the Mortgaged Property; (11) any awards, remunerations, reimbursements, settlements or compensation heretofore made to Grantor or hereafter to be made to Grantor by any governmental authority pertaining to the Land, Improvements or Fixtures; and (12) all accessions, replacements and substitutions for any of the foregoing and all proceeds thereof. The term “Mortgaged Property” shall mean all or, where the context permits or requires, any portion of the above items or any interest therein. The Mortgaged Property does not include any Excluded Property.
“Obligations” means the Second Lien Obligations as defined in the Security Agreement.
“Owned Land” means the portion of the Land fee simple title to which is owned by Grantor.
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“Permitted Liens” means: (1) Permitted Liens as defined in the Indenture; (2) in any event, any title exceptions shown in the mortgagee policy of title insurance issued or to be issued by Fidelity National Title Insurance Company to Beneficiary with respect to the Mortgaged Property in accordance with Section 11.05(b) of the Indenture (the “Title Policy”), and (3) in any event, any First Lien Obligations.
“Real Estate” means the Owned Land, the Mortgaged Leased Land, the Easement Land and the Improvements and Fixtures located thereon.
“Related Parties” shall mean, with respect to any specified Person, such Person’s Affiliates and the directors, officers, employees, agents, trustees and advisors of such Person and any Person that possesses, directly or indirectly, the power to direct or cause the direction of the management or policies of such Person, whether through the ability to exercise voting power, by contract or otherwise.
“Second Lien Security Documents” means the Indenture, any Additional Second Lien Agreement, and any of the Security Documents.
“Second Lien Secured Parties” has the meaning given to it in the Security Agreement.
“Security Agreement” means that Second Lien Security Agreement dated as of October 6, 2010, among Issuer, Grantor, the Subsidiary Grantors (as defined therein) party thereto, and the Bank of New York Mellon Trust Company, N.A. as Beneficiary and the Initial Second Priority Representative (as defined in the Intercreditor Agreement).
“UCC” means the Uniform Commercial Code as in effect in the State of Texas, as amended from time to time.
“Warranty Property” means: (i) the Land described inExhibit A (the “Warranty Land”); (ii) the Leasehold Estate described inExhibit B (the “Warranty Leasehold Estate”); (iii) the Easement Rights described inExhibit C (the “Warranty Easement Rights”); (iv) all buildings, structures and other improvements now located on the Warranty Land, excluding the Unbundling Exception Portion (the “Warranty Fee Improvements”); (v) the buildings, structures and other improvements now located on the Mortgaged Leased Land, excluding the reversionary interest therein of the landlord of the Mortgaged Lease or its successor in interest as owner of the Mortgaged Leased Land (the “Warranty Leasehold Improvements”); (vi) the buildings, structures and other improvements now located on the Easement Land, excluding the reversionary interest therein of the grantor of the Easement Rights or its successor in interest as owner of the Easement Land (the “Warranty Easement Improvements”); (vii) all goods that constitute fixtures under the UCC that are now installed in or attached to the Warranty Land, the Mortgaged Leased Land, the Easement Land or the Improvements, subject to the exclusions in clauses (iv), (v) and (vi) of this definition (the “Warranty Fixtures”); and (viii) the Water Rights derived from each certificate of adjudication described inExhibit D (the “Warranty Water Rights”).
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In addition:
(a) All capitalized terms used in this Deed of Trust but not defined herein shall have the meanings given to them in the Indenture;
(b) The words “hereof, “herein”, “hereto” and “hereunder” and words of similar import when used in this Deed of Trust shall refer to this Deed of Trust as a whole and not to any particular provision of this Deed of Trust, and Section, subsection and Schedule references are to this Deed of Trust unless otherwise specified;
(c) The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”; and
(d) Unless the context clearly indicates a contrary intent or unless otherwise specifically provided herein, words used in this Deed of Trust shall be used interchangeably in singular or plural form and the word “Grantor” shall mean “each Grantor or any subsequent owner or owners of the Mortgaged Property or any part thereof or interest therein,” the word “Beneficiary” shall mean “Beneficiary or any successor collateral agent for the Second Lien Secured Parties,” (or such other capacities under any Additional Second Lien Agreement and any successors to such other capacities), the word “Trustee” shall mean “Trustee and any successor trustee hereunder,” the word “person” shall include any individual, corporation, partnership, limited liability company, trust, unincorporated association, government, governmental authority, or other entity, and the words “Mortgaged Property” shall include any portion of the Mortgaged Property or interest therein. Whenever the context may require, any pronouns used herein shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns and pronouns shall include the plural and vice versa. The captions in this Deed of Trust are for convenience of reference only and in no way limit or amplify the provisions hereof.
| 2. | GRANT |
For the ratable benefit of the Second Lien Secured Parties and to secure the full and timely payment and performance of the Obligations, Grantor MORTGAGES, GRANTS, BARGAINS, SELLS and CONVEYS, to Trustee, IN TRUST, WITH POWER OF SALE, the Mortgaged Property, subject, however, only to Permitted Liens; TO HAVE AND TO HOLD the Mortgaged Property together with the rights, privileges and appurtenances thereto belonging to Trustee and to its substitutes or successors, forever; and Grantor does hereby bind itself, its successors and assigns to WARRANT AND FOREVER DEFEND the title to the Mortgaged Property, subject to Permitted Liens, unto Trustee and to its substitutes or successors against the claim or claims of every person whomsoever lawfully claiming or to claim the same or any part thereof.
TO HAVE AND TO HOLD the Mortgaged Property unto the Trustee and/or Beneficiary, their respective successors and assigns for the uses and purposes set forth, until the Obligations are fully paid and performed, provided, however, that the condition of this Deed of Trust is such that if the Obligations are fully paid and performed in accordance with the provisions of the Second Lien Security Documents, then the estate hereby granted shall cease, terminate and become void but shall otherwise remain in full force and effect.
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The liens and security interests created by this Deed of Trust shall be, until such time as all First Lien Obligations have been satisfied in full, a second priority lien (subject to Permitted Liens), subordinate in all respects (including the exercise of remedies with respect to the Mortgaged Property covered hereby) to the prior lien of the applicable mortgage encumbering the Mortgage Property and securing the First Lien Obligations on and subject to the terms and conditions set forth in the Intercreditor Agreement. Notwithstanding anything herein to the contrary, the lien and security interest granted hereunder and the exercise of any rights or remedies by Trustee and Beneficiary hereunder are subject to the provisions of the Intercreditor Agreement. In the event of any conflict or inconsistency between the terms of the Intercreditor Agreement and this Deed of Trust, the terms of the Intercreditor Agreement shall govern.
To the extent this Deed of Trust secures Additional Second Lien Obligations pursuant to any Additional Second Lien Agreement, such Additional Second Lien Obligations shall be so secured if and when made in accordance with the conditions set forth in Section 8.17 of the Security Agreement, at which time Grantor will execute and record a supplement or amendment to this Deed of Trust in confirmation of and to secure such Additional Second Lien Obligations. It is the express intention of Grantor hereunder that any and all Additional Second Lien Obligations shall be secured with the same priority as if made on the date of execution of this Deed of Trust.
| 3. | WARRANTIES, REPRESENTATIONS AND COVENANTS |
Grantor warrants, represents and covenants to Trustee and Beneficiary as follows:
3.1Title to Mortgaged Property and Lien of this Instrument; Warranties Regarding Warranty Property. Grantor warrants that Grantor has good title in fee simple in and to the Warranty Land, a valid leasehold estate under the Mortgaged Leases described inExhibit B, a valid easement estate under the Warranty Easements Rights, and good title to the Warranty Fee Improvements, the Warranty Leasehold Improvements and the Warranty Easement Improvements, the Warranty Fixtures and the Warranty Water Rights, and upon acquisition thereof by Grantor, will have good title in fee simple, leasehold or easement estate, as applicable, in the portion of the Mortgage Property hereafter acquired by Grantor, in each case free and clear of any Liens except for Permitted Liens, except where the failure to have such good title could not reasonably be expected to have a Material Adverse Effect. This Deed of Trust creates valid, enforceable liens and security interests against the Mortgaged Property, subject to Permitted Liens, and upon recording of this Deed of Trust in the real property records of the county or counties in which the Mortgaged Property is situated and this Deed of Trust being indexed as a fixture, timber and as-extracted collateral filing in such records, this Deed of Trust will create and constitute a valid and enforceable mortgage Lien on and UCC security interest in the portion of the Mortgaged Property that is fixtures, timber to be cut and as-extracted collateral, subject to Permitted Liens. Grantor shall preserve and protect the Lien (including the priority thereof) and security interest of this Deed of Trust and the other Second Lien Security Documents insofar as they refer to the Mortgaged Property, subject only to Permitted Liens, to the extent necessary to avoid causing a Material Adverse Effect.
3.2Payment of Obligations. Grantor shall pay and perform the Obligations at the times and places and in the manner specified in the Second Lien Security Documents.
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3.3Requirements. Grantor shall comply with all covenants, restrictions and conditions now or later of record which may be applicable to any of the Mortgaged Property, or to the use, manner of use, occupancy, possession, operation, maintenance, alteration, repair or reconstruction of any of the Mortgaged Property, except where a failure to do so could not reasonably be expected to have a Material Adverse Effect.
3.4Payment of Taxes and Other Impositions. (a) Except as prohibited by the Indenture, Grantor shall, prior to the date on which any fine, penalty, interest or cost may be added thereto or imposed, pay and discharge all taxes, charges and assessments of every kind and nature, all charges for any easement or agreement maintained for the benefit of any of the Real Estate, all general and special assessments, levies, permits, inspection and license fees, all water and sewer rents and charges, all vault taxes and all other public charges even if unforeseen or extraordinary, imposed upon or assessed against or that may become a material lien on any of the Real Estate, or arising in respect of the occupancy, use or possession thereof, together with any penalties or interest on any of the foregoing (all of the foregoing are collectively referred to herein as the “Impositions”), except where the validity or amount thereof is being contested in good faith and by proper proceedings, so long as Grantor maintains adequate reserves (in the good faith judgment of the management of the Issuer) with respect thereto in accordance with GAAP and the failure to pay could not reasonably be expected to result in a Material Adverse Effect. If by law any Imposition may be paid in installments (whether or not interest shall accrue on the unpaid balance of such Imposition), Grantor may elect to pay such Imposition in such installments and shall be responsible for the payment of such installments with interest, if any.
(b) Nothing herein shall affect any right or remedy of Trustee or Beneficiary under this Deed of Trust or otherwise, following the occurrence and during the continuance of an Event of Default, without notice or demand to Grantor, to pay any Imposition after the date such Imposition shall have become delinquent, and add to the Obligations the amount so paid, together with interest from the time of payment at the default rate determined in accordance with Section 2.12 of the Indenture (interest accrued at such rate being referred to herein as “Default Interest”). Any sums paid by Trustee or Beneficiary in discharge of any Impositions shall be (i) a lien on the Premises secured hereby prior to any right or title to, interest in, or claim upon the Premises subordinate to the lien of this Deed of Trust, and (ii) payable on demand by Grantor to Trustee or Beneficiary, as the case may be, together with Default Interest.
3.5Insurance. Mortgagor will keep or cause to be kept the Mortgaged Property insured against such risks and shall purchase such additional insurance to the extent that is required from time to time pursuant to Section 4.17 of the Indenture.
3.6Restrictions on Liens and Encumbrances. Except for the lien of this Deed of Trust and the Permitted Liens, Grantor shall not further mortgage, nor otherwise encumber the Mortgaged Property nor create or suffer to exist any lien, charge or encumbrance on the Mortgaged Property, or any part thereof, whether superior or subordinate to the lien of this Deed of Trust and whether recourse or non-recourse.
3.7Due on Sale and Other Transfer Restrictions. Except as expressly permitted under the Indenture or herein, Grantor shall not sell, transfer, convey or assign all or any portion of, or any interest in, the Mortgaged Property.
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3.8Condemnation/Eminent Domain. Promptly upon obtaining knowledge of the institution of any proceedings for the condemnation of the Mortgaged Property, or any material portion thereof, Grantor will notify Beneficiary of the pendency of such proceedings. All awards and proceeds relating to such condemnation shall be deemed Net Proceeds and applied in the manner specified in Section 4.10 of the Indenture.
3.9Leases. Except as expressly permitted under the Indenture, Grantor shall not (a) execute an assignment or pledge of any Lease relating to all or any portion of the Mortgaged Property other than in favor of Beneficiary, or (b) execute or permit to exist any Lease of any of the Mortgaged Property.
3.10Further Assurances. To the extent required under the terms of the Indenture, to further assure Beneficiary’s rights under this Deed of Trust, Grantor agrees promptly upon demand of Beneficiary to do any act or execute any additional documents (including, but not limited to, security agreements on any personalty included or to be included in the Mortgaged Property and a separate assignment of each Lease in recordable form) as may be reasonably required by Beneficiary to confirm the lien of this Deed of Trust and all other rights or benefits conferred on Beneficiary by this Deed of Trust.
3.11Beneficiary’s Right to Perform. Upon the occurrence and during the continuance of an Event of Default, Beneficiary or Trustee, may, at any time upon 5 days’ notice to Grantor (but shall be under no obligation to) pay or perform any delinquent obligations of Grantor hereunder, and the amount or cost thereof, with Default Interest, shall immediately be due from Grantor to Beneficiary or Trustee (as the case may be) and the same shall be secured by this Deed of Trust and shall be a lien on the Mortgaged Property prior to any right, title to, interest in, or claim upon the Mortgaged Property attaching subsequent to the lien of this Deed of Trust. No payment or advance of money by Beneficiary or Trustee under this Section shall be deemed or construed to cure Grantor’s default or waive any right or remedy of Beneficiary or Trustee.
| 4. | LIMITATION ON AMOUNT OBLIGATED; CONTRIBUTION BY OTHER PERSONS |
Anything contained in this Deed of Trust to the contrary notwithstanding, if any Fraudulent Transfer Law (as hereinafter defined) is determined by a court of competent jurisdiction to be applicable to the obligations of Grantor under this Deed of Trust, such obligations shall be limited to the maximum aggregate amount that would not render Grantor’s obligations under this Deed of Trust subject to avoidance as a fraudulent transfer or conveyance under Section 548 of Title 11 of the United States Code or any applicable provisions of comparable state law (collectively, the “Fraudulent Transfer Laws”), in each case after giving effect to all other liabilities of Grantor, contingent or otherwise, that are relevant under the Fraudulent Transfer Laws, and giving effect as assets to the value (as determined under the applicable provisions of the Fraudulent Transfer Laws) of any rights to subrogation, reimbursement, indemnification, or contribution of Grantor pursuant to applicable law or pursuant to the terms of any agreement.
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| 5. | REMEDIES |
(a) Upon the occurrence and during the continuance of any Event of Default, Beneficiary may immediately take such action, without notice or demand, as it deems advisable to protect and enforce its rights against Grantor and in and to the Mortgaged Property, including, but not limited to, the following actions, each of which may be pursued concurrently or otherwise, at such time and in such manner as Trustee or Beneficiary (as the case may be) may determine, in its sole discretion, without impairing or otherwise affecting the other rights and remedies of Beneficiary:
(i) Upon the occurrence and during the continuance of an Event of Default, Trustee is hereby authorized and empowered to sell or offer for sale at one or more sales, as an entirety or in parcels, as Trustee may elect, all or any part of the Mortgaged Property located in the State of Texas, with or without having first taken possession of same, to the highest bidder for cash at public auction. Such sale or sales shall be made at the courthouse of the county in Texas in which the Mortgaged Property or any part thereof is situated, as herein described, between the hours of 10:00 a.m. and 4:00 p.m. on the first Tuesday of any month, beginning within three (3) hours of the time provided in the notices described herein. Trustee shall post a written or printed notice or notices of the place, earliest time at which the sale will begin and the terms of said sale, and the portion of the Mortgaged Property to be sold, for at least twenty-one (21) days preceding the date of the sale, at the courthouse door of said county in which the sale is to be made; and if such Mortgaged Property lies in more than one county, one such notice of sale shall be posted at the courthouse door of each county in which such Mortgaged Property is situated and such Mortgaged Property may be sold at the area designated by the commissioners court of any one of such counties, and the notice so posted shall designate in which county such property shall be sold. In addition to such posting of notice, Beneficiary, Trustee or the other holder of the secured indebtedness (or some person or persons acting for the Trustee, Beneficiary, or other such holder) shall, at least twenty-one (21) days preceding the date of sale, file a copy of such notice(s) in the office of the county clerk in each of such counties and serve or cause to be served written notice of the proposed sale by certified mail on Grantor and on each other party, if any, obligated to pay the secured indebtedness according to the records of Beneficiary. Service of such notice shall be completed upon deposit of the notice, enclosed in a postpaid wrapper properly addressed to Grantor and such other parties at their most recent address or addresses as shown by the records of Beneficiary, in a post office or official depository under the care and custody of the United States Postal Service. The affidavit of any person having knowledge of the facts to the effect that such a service was completed shall be prima facie evidence of the fact of service. Grantor agrees that no notice of any sale, other than as set out in this paragraph, need be given by Trustee, Beneficiary, or any other person. Grantor authorizes and empowers Trustee to sell the Mortgaged Property in lots or parcels or in its entirety as Trustee shall deem expedient; and to execute and deliver to the purchaser or purchasers thereof good and sufficient deeds of conveyance thereto, with evidence of general warranty by Grantor. Trustee may postpone the sale of all or any part of the Mortgaged Property by public announcement at the time and place of such sale, and from time to time thereafter may further postpone such sale by public announcement made at the time of sale fixed by the preceding postponement. The right
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of sale hereunder shall not be exhausted by one or any sale, and Trustee may make other and successive sales until all of the trust estate be legally sold. The provisions hereof with respect to the posting and giving of notices of sale are intended to comply with the provisions of Section 51.002 of the Texas Property Code as in effect on the date hereof, and in the event that the requirements of Section 51.002 of the Texas Property Code shall be modified or repealed in the future, by amendment, superceding statute or otherwise, and such amendment, statute or other action applies to the enforcement of pre-existing instruments, then the terms of this Section shall be deemed to be modified accordingly, effective as of the effective date of such modification or repeal;
(ii) Beneficiary may, to the extent permitted by applicable law, (A) institute and maintain an action of mortgage foreclosure against all or any part of the Mortgaged Property, (B) institute and maintain an action on the Second Lien Security Documents, or (C) take such other action at law or in equity for the enforcement of this Deed of Trust or any of the Second Lien Security Documents as the law may allow. Beneficiary may proceed in any such action to final judgment and execution thereon for all sums due hereunder, together with Default Interest thereon and all costs of suit, including, without limitation, reasonable attorneys’ fees and disbursements. Default Interest, to the extent permitted by applicable law, shall be due on any judgment obtained by Beneficiary from the date of judgment until actual payment is made of the full amount of the judgment; and
(iii) Beneficiary may personally, or by its agents, attorneys and employees and without regard to the adequacy or inadequacy of the Mortgaged Property or any other collateral as security for the Obligations enter into and upon the Mortgaged Property and each and every part thereof and exclude Grantor and its agents and employees therefrom without liability for trespass, damage or otherwise (Grantor hereby agreeing to surrender possession of the Mortgaged Property to Beneficiary upon demand at any such time) and use, operate, manage, maintain and control the Mortgaged Property and every part thereof. Following such entry and taking of possession, Beneficiary shall be entitled, without limitation, (x) to lease all or any part or parts of the Mortgaged Property for such periods of time and upon such conditions as Beneficiary may, in its discretion, deem proper, (y) to enforce, cancel or modify any Lease and (z) generally to execute, do and perform any other act, deed, matter or thing concerning the Mortgaged Property as Beneficiary shall deem appropriate as fully as Grantor might do.
(b) In case of a foreclosure sale, the Real Estate may be sold, at Trustee’s election, in one parcel or in more than one parcel and Trustee is specifically empowered (without being required to do so, and in its sole and absolute discretion) to cause successive sales of portions of the Mortgaged Property to be held.
(c) In the event of any breach of any of the covenants, agreements, terms or conditions contained in this Deed of Trust, Beneficiary, and to the extent permitted by applicable law and principles of equity, shall be entitled to enjoin such breach and/or obtain specific performance of any covenant, agreement, term or condition and Beneficiary shall have the right to invoke any equitable right or remedy as though other remedies were not provided for in this Deed of Trust.
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(d) It is agreed that if an Event of Default shall occur and be continuing, any and all proceeds of the Mortgaged Property received by Trustee or Beneficiary shall be held by Trustee for Beneficiary for the benefit of the Second Lien Secured Parties or by Beneficiary for the benefit of the Second Lien Secured Parties as collateral security for the Obligations (whether matured or unmatured), and shall be applied in payment of the Obligations in the manner set forth in Section 5.3 of the Security Agreement.
| 6. | RIGHT OF BENEFICIARY TO CREDIT SALE |
Upon the occurrence of any sale made under this Deed of Trust, whether made under the power of sale or by virtue of judicial proceedings or of a judgment or decree of foreclosure and sale, Beneficiary may bid for and acquire the Mortgaged Property or any part thereof. In lieu of paying cash therefor, Beneficiary may make settlement for the purchase price by crediting upon the Obligations or other sums secured by this Deed of Trust, the net sales price after deducting therefrom the expenses of sale and the cost of the action and any other sums which Beneficiary is authorized to deduct under this Deed of Trust. In such event, this Deed of Trust, the Second Lien Security Documents and all other documents evidencing expenditures secured hereby may be presented to the person or persons conducting the sale in order that the amount so used or applied may be credited upon the Obligations as having been paid.
| 7. | APPOINTMENT OF RECEIVER |
If an Event of Default shall have occurred and be continuing, Beneficiary as a matter of right and without notice to Grantor, unless otherwise required by applicable law, and without regard to the adequacy or inadequacy of the Mortgaged Property or any other collateral or the interest of Grantor therein as security for the Obligations, shall have the right to apply to any court having jurisdiction to appoint a receiver or receivers of the Mortgaged Property, without requiring the posting of a surety bond, and without reference to the adequacy of the value of the Mortgaged Property or the solvency or insolvency of Grantor or any other party obligated for payment of all or any part of the Obligations, and whether or not waste has occurred with respect to the Mortgaged Property, and Grantor hereby irrevocably consents to such appointment and waives notice of any application therefor (except as may be required by law). Any such receiver or receivers shall have all the usual powers and duties of receivers in like or similar cases and all the powers and duties of Beneficiary in case of entry as provided in this Deed of Trust, including, without limitation and to the extent permitted by law, the right to enter into leases of all or any part of the Mortgaged Property, and shall continue as such and exercise all such powers until the date of confirmation of sale of the Mortgaged Property unless such receivership is sooner terminated.
| 8. | EXTENSION, RELEASE, ETC |
(a) Without affecting the lien or charge of this Deed of Trust upon any portion of the Mortgaged Property not then or theretofore released as security for the full amount of the Obligations, Beneficiary may, from time to time and without notice, agree to (i) release any person liable for the indebtedness borrowed or guaranteed under the Second Lien Security Documents, (ii) extend the maturity or alter any of the terms of the indebtedness borrowed or guaranteed under the Second Lien Security Documents or any other guaranty thereof, (iii) grant
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other indulgences, (iv) release or reconvey, or cause to be released or reconveyed at any time at Beneficiary’s option any parcel, portion or all of the Mortgaged Property, (v) take or release any other or additional security for any obligation herein mentioned, or (vi) make compositions or other arrangements with debtors in relation thereto.
(b) No recovery of any judgment by Beneficiary and no levy of an execution under any judgment upon the Mortgaged Property or upon any other property of Grantor shall affect the lien of this Deed of Trust or any liens, rights, powers or remedies of Beneficiary hereunder, and such liens, rights, powers and remedies shall continue unimpaired.
(c) If Beneficiary shall have the right to foreclose this Deed of Trust or to direct the Trustee to exercise its power of sale, Grantor authorizes Beneficiary at its option to foreclose the lien of this Deed of Trust (or direct the Trustee to sell the Mortgaged Property, as the case may be) subject to the rights of any tenants of the Mortgaged Property. The failure to make any such tenants parties defendant to any such foreclosure proceeding and to foreclose their rights, or to provide notice to such tenants as required in any statutory procedure governing a sale of the Mortgaged Property, or to terminate such tenant’s rights in such sale will not be asserted by Grantor as a defense to any proceeding instituted by Beneficiary to collect the Obligations or to foreclose the lien of this Deed of Trust.
(d) Unless expressly provided otherwise, in the event that Beneficiary’s interest in this Deed of Trust and title to the Mortgaged Property or any estate therein shall become vested in the same person or entity, this Deed of Trust shall not merge in such title but shall continue as a valid lien on the Mortgaged Property for the amount secured hereby.
| 9. | SECURITY AGREEMENT UNDER UNIFORM COMMERCIAL CODE; FIXTURE FILING |
(a) It is the intention of the parties hereto that this Deed of Trust shall constitute a “security agreement” within the meaning of the UCC. To that end, Grantor hereby grants to Trustee and Beneficiary, for the ratable benefit of the Second Lien Secured Parties, a security interest in the Fixtures, Leases, Rents, timber to be cut and as-extracted collateral, all to secure payment and performance of the Obligations. If an Event of Default shall occur and be continuing, then in addition to having any other right or remedy available at law or in equity, Beneficiary shall have the option of either (i) proceeding under the UCC and exercising such rights and remedies as may be provided to a secured party by the UCC with respect to all or any portion of the Mortgaged Property that is personal property (including, without limitation, taking possession of and selling such property) or (ii) treating such property as real property and proceeding with respect to both the real and personal property constituting the Mortgaged Property in accordance with Beneficiary’s rights, powers and remedies with respect to the Real Estate (in which event the default provisions of the UCC shall not apply). If Beneficiary shall elect to proceed under the UCC, then ten (10) days’ notice of sale of the personal property shall be deemed reasonable notice and the reasonable expenses of retaking, holding, preparing for sale, selling and the like incurred by Beneficiary shall include, but not be limited to, attorneys’ fees and legal expenses. At Beneficiary’s request, Grantor shall assemble the personal property and make it available to Beneficiary at a place designated by Beneficiary which is reasonably convenient to both parties.
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(b) Certain portions of the Mortgaged Property are or will become “fixtures”, “timber to be cut” or “as-extracted collateral” (as defined in the UCC) on the Owned Land, the Mortgage Leased Land, the Easement Land or the Improvements located thereon, and this Deed of Trust, upon being filed for record in the real estate records of the county wherein such fixtures, timber to be cut or as-extracted collateral are situated, shall operate also as a financing statement filed as a fixture filing in accordance with the applicable provisions of said UCC upon such portions of the Mortgaged Property that are or become fixtures. The Land, Mortgaged Leased Land and Easement Land to which the fixtures relate is described inExhibit A,Exhibit B andExhibit C respectively hereto. The record owner of (i) the Land described inExhibit A hereto is the Grantor, (ii) the Mortgaged Leased Land described inExhibit B hereto is the landlord under the Mortgaged Leases described in such exhibit or its successor in interest as owner of the Mortgaged Leased Land, and (iii) the Easement Land described inExhibit C hereto is grantor of the Easement Rights described in such exhibit or its successor in interest as owner of the Easement Land. The name, type of organization and jurisdiction of organization of the debtor for purposes of this financing statement are the name, type of organization and jurisdiction of organization of the Grantor set forth in the first paragraph of this Deed of Trust, and the name of the secured party for purposes of this financing statement is the name of Beneficiary set forth in the first paragraph of this Deed of Trust. The mailing address of the Grantor/debtor is the address of the Grantor set forth in the first paragraph of this Deed of Trust. The mailing address of Beneficiary/the secured party from which information concerning the security interest hereunder may be obtained is the address of Beneficiary set forth in the first paragraph of this Deed of Trust. Grantor’s organizational identification number is set forth in the first paragraph of this Deed of Trust.
| 10. | ASSIGNMENT OF RENTS |
(a) Grantor hereby assigns to Beneficiary the Rents as further security for the payment of and performance of the Obligations, and Grantor grants to Beneficiary the right to enter the Mortgaged Property for the purpose of collecting the same and to let the Mortgaged Property or any part thereof, and to apply the Rents on account of the Obligations. The foregoing assignment and grant is present and absolute and shall continue in effect until the Obligations are fully paid and performed, but Beneficiary hereby waives the right to enter the Mortgaged Property for the purpose of collecting the Rents and Grantor shall be entitled to collect, receive, use and retain the Rents unless an Event of Default has occurred and for so long as such Event of Default continues; such right of Grantor to collect, receive, use and retain the Rents may be revoked by Beneficiary upon the occurrence and during the continuance of any Event of Default by giving not less than five days’ written notice of such revocation to Grantor. In the event such notice is given, Grantor shall pay over to Beneficiary, or to any receiver appointed to collect the Rents, any lease security deposits, and shall pay monthly in advance to Beneficiary, or to any such receiver, the fair and reasonable rental value as determined by Beneficiary for the use and occupancy of such part of the Mortgaged Property as may be in the possession of Grantor or any affiliate of Grantor, and upon default in any such payment Grantor and any such affiliate will vacate and surrender the possession of the Mortgaged Property to Beneficiary or to such receiver, and in default thereof may be evicted by summary proceedings or otherwise. Grantor shall not accept prepayments of installments of Rent to become due for a period of more than one month in advance (except for security deposits and estimated payments of percentage rent, if any).
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(b) Grantor has not affirmatively done any act that would prevent Beneficiary from, or limit Beneficiary in, acting under any of the provisions of the foregoing assignment.
(c) Except for any matter disclosed in the Indenture, no action has been brought or, so far as is known to Grantor, is threatened, that would interfere in any way with the right of Grantor to execute the foregoing assignment and perform all of Grantor’s obligations contained in this Section and in the Leases.
| 11. | ADDITIONAL RIGHTS |
The holder of any subordinate lien or subordinate deed of trust on the Mortgaged Property shall have no right to terminate any Lease whether or not such Lease is subordinate to this Deed of Trust nor shall Grantor consent to any holder of any subordinate lien or subordinate deed of trust joining any tenant under any Lease in any trustee’s sale or action to foreclose such subordinate lien or modify, interfere with, disturb or terminate the rights of any tenant under any Lease. By recordation of this Deed of Trust all subordinate lienholders and the trustees and beneficiaries under subordinate mortgages are subject to and notified of this provision, and any action taken by any such lienholder or beneficiary contrary to this provision shall be null and void. Any such application shall not be construed to cure or waive any Default or Event of Default or invalidate any act taken by Beneficiary on account of such Default or Event of Default.
| 12. | NOTICES |
All notices, requests and demands to or upon Beneficiary or the Grantor hereunder shall be effected in the manner provided for in Section 13.02 of the Indenture; provided that any such notice, request or demand to or upon Grantor shall be addressed to Grantor at its address set forth above.
| 13. | NO ORAL MODIFICATION |
This Deed of Trust may not be amended, supplemented or otherwise modified except in accordance with the provisions of Article 9 of the Indenture. Any agreement made by Grantor and Beneficiary after the date of this Deed of Trust relating to this Deed of Trust shall be superior to the rights of the holder of any intervening or subordinate lien or encumbrance. Trustee’s execution of any written agreement between Grantor and Beneficiary shall not be required for the effectiveness thereof as between Grantor and Beneficiary.
| 14. | PARTIAL INVALIDITY |
In the event any one or more of the provisions contained in this Deed of Trust shall for any reason be held to be invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision hereof, but each shall be construed as if such invalid, illegal or unenforceable provision had never been included. Notwithstanding anything to the contrary contained in this Deed of Trust or in any provisions of any Second Lien Security Document, the obligations of Grantor and of any other obligor under any Second Lien Security Document shall be subject to the limitation that Beneficiary shall not charge, take or receive, nor shall Grantor or any other obligor be obligated to pay to Beneficiary, any amounts constituting interest in excess of the maximum rate permitted by law to be charged by Beneficiary.
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| 15. | GRANTOR’S WAIVER OF RIGHTS |
(a) Grantor hereby voluntarily and knowingly releases and waives any and all rights to retain possession of the Mortgaged Property upon the occurrence and during the continuance of an Event of Default and any and all rights of redemption from sale under any order or decree of foreclosure (whether full or partial), pursuant to rights, if any, therein granted, as allowed under any applicable law, on its own behalf, on behalf of all persons claiming or having an interest (direct or indirectly) by, through or under Grantor and on behalf of each and every person acquiring any interest in the Mortgaged Property subsequent to the date hereof, it being the intent hereof that any and all such rights of redemption of Grantor and all such other persons are and shall be deemed to be hereby waived to the fullest extent permitted by applicable law or replacement statute. To the fullest extent permitted by applicable law, Grantor shall not invoke or utilize any such law or laws or otherwise hinder, delay, or impede the execution of any right, power, or remedy herein or otherwise granted or delegated to Beneficiary, but shall permit the execution of every such right, power, and remedy as though no such law or laws had been made or enacted.
(b) To the fullest extent permitted by law, Grantor waives the benefit of all laws now existing or that may subsequently be enacted providing for (i) any appraisement before sale of any portion of the Mortgaged Property, (ii) any extension of the time for the enforcement of the collection of the Obligations or the creation or extension of a period of redemption from any sale made in collecting such debt and (iii) exemption of the Mortgaged Property from attachment, levy or sale under execution or exemption from civil process. To the full extent Grantor may do so, Grantor agrees that Grantor will not at any time insist upon, plead, claim or take the benefit or advantage of any law now or hereafter in force providing for any appraisement, valuation, stay, exemption, extension or redemption, or requiring foreclosure of this Deed of Trust before exercising any other remedy granted hereunder and Grantor, for Grantor and its successors and assigns, and for any and all persons ever claiming any interest in the Mortgaged Property, to the extent permitted by law, hereby waives and releases all rights of redemption, valuation, appraisement, stay of execution, notice of election to mature (except as expressly provided in the Indenture) or declare due the whole of the secured indebtedness and marshalling in the event of exercise by Trustee or Beneficiary of the foreclosure rights, power of sale, or other rights hereby created.
| 16. | REMEDIES NOT EXCLUSIVE |
(a) Beneficiary and Trustee shall be entitled to enforce payment and performance of the Obligations and to exercise all rights and powers under this Deed of Trust or under any of the other Second Lien Security Documents or other agreement or any laws now or hereafter in force, notwithstanding some or all of the Obligations may now or hereafter be otherwise secured, whether by deed of trust, mortgage, security agreement, pledge, lien, assignment or otherwise. Neither the acceptance of this Deed of Trust nor its enforcement, shall prejudice or in any manner affect Beneficiary’s or Trustee’s right to realize upon or enforce any other security now or hereafter held by Beneficiary or Trustee, it being agreed that Beneficiary and Trustee shall be
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entitled to enforce this Deed of Trust and any other security now or hereafter held by Beneficiary or Trustee in such order and manner as Beneficiary or Trustee may determine in its absolute discretion. No remedy herein conferred upon or reserved to Trustee or Beneficiary is intended to be exclusive of any other remedy herein or by law provided or permitted, but each shall be cumulative and shall be in addition to every other remedy given hereunder or now or hereafter existing at law or in equity or by statute. Every power or remedy given by any of the Second Lien Security Documents to Beneficiary or Trustee or to which either may otherwise be entitled, may be exercised, concurrently or independently, from time to time and as often as may be deemed expedient by Beneficiary or Trustee, as the case may be. In no event shall Beneficiary or Trustee, in the exercise of the remedies provided in this Deed of Trust (including, without limitation, in connection with the assignment of Rents to Beneficiary, or the appointment of a receiver and the entry of such receiver on to all or any part of the Mortgaged Property), be deemed a “mortgagee in possession,” and neither Beneficiary nor Trustee shall in any way be made liable for any act, either of commission or omission, in connection with the exercise of such remedies.
(b) Without limiting the generality of Section 16(a), except as otherwise provided in Section 16(c) below, neither the enforcement of any of the remedies under Sections 5 and 16 hereof, the security interests under Section 9, the assignment of Rents under Section 10, nor any other remedies afforded to Beneficiary under the Second Lien Security Documents, at law or in equity shall cause Beneficiary, any Second Lien Secured Party or Trustee to be deemed or construed to be a mortgagee in possession of the Mortgaged Property, to obligate Beneficiary, any Second Lien Secured Party or Trustee to lease the Mortgaged Property or attempt to do so, or to take any action, incur any expense, or perform or discharge any obligation, duty or liability whatsoever under any of the Leases or otherwise.
(c) Notwithstanding the provisions of Section 16(b) above, Beneficiary shall not obtain title to a deed in lieu of foreclosure or otherwise, or take any other action with respect to the Mortgaged Property, if, as a result of any such action, Beneficiary could, in its reasonable judgment be considered to hold title to, to be a “mortgagee-in-possession” of, or to be an “owner” or “operator” of the Mortgaged Property within the meaning of Comprehensive Environmental Response, Compensation and Liability Act Of 1980 (42 U.S.C. Sections 9601 et seq.), as amended, or any comparable law, unless:
(i) Beneficiary has previously and reasonably determined, based on a Phase I environmental site assessment (and any additional environmental testing that Beneficiary deems necessary and prudent) of such Mortgaged Property conducted by an independent third party who regularly conducts Phase I environmental site assessments and performed during the 12-month period preceding any such acquisition of title or other action, that the Mortgaged Property is in compliance with applicable environmental laws and regulations and there are no circumstances or conditions present at the Mortgaged Property relating to the use, management or disposal of Hazardous Materials for which investigation, testing, monitoring, containment, clean-up or remediation could be required under any applicable environmental laws and regulations; or
(ii) in the event that the determination described in clause (i) above cannot be made, Beneficiary has previously and reasonably determined, on the same basis as
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described in clause (i) above, that it would maximize the recovery to the Second Lien Secured Parties on a present value basis to acquire title to or possession of the Mortgaged Property and to take such remedial, corrective and/or other further actions as are necessary to bring the Mortgaged Property into compliance with applicable environmental laws and regulations and to appropriately address any of the circumstances and conditions referred to in clause (i) above.
(d) Beneficiary shall undertake, in good faith, reasonable efforts to make the determination referred to in clause (ii) above, and may conclusively rely on the Phase I environmental site assessment referred to above, and upon an opinion of counsel, in making such determination. The cost of any such Phase I environmental site assessment and any such opinion of counsel, and the cost of any Phase II environmental site assessment, additional environmental testing and remedial, corrective or other further action contemplated by clause (i) or clause (ii) above, shall be paid at the sole expense of Grantor.
(e) If the environmental testing contemplated by Section 16(b) above establishes that any of the conditions set forth in clause (i) have not been satisfied with respect to the Mortgaged Property, Beneficiary shall take such action (other than proceeding against the Mortgaged Property) and, at such time as it deems appropriate, may release all or a portion of such Mortgaged Property from the lien of this Deed of Trust, provided that prior to the release of all or a portion of the Mortgaged Property from the lien of this Deed of Trust (i) Beneficiary shall have notified the Second Lien Secured Parties in writing of its intention to so release all or a portion of such Mortgaged Property and (ii) the holders of a majority of the outstanding principal balance of the Obligations shall not have objected to such release within thirty (30) days of the distribution of the last of such notices.
| 17. | MULTIPLE SECURITY |
If (a) the Land shall consist of one or more parcels, whether or not contiguous and whether or not located in the same county, or (b) in addition to this Deed of Trust, Beneficiary shall now or hereafter hold or be the beneficiary of one or more additional mortgages, liens, deeds of trust or other security (directly or indirectly) for the Obligations upon other property in the State in which the Land is located (whether or not such property is owned by Grantor or by others) or (c) both the circumstances described in clauses (a) and (b) shall be true, then to the fullest extent permitted by law, and after giving all notices required by law, Beneficiary may, at its election, commence or consolidate in a single trustee’s sale or foreclosure action all trustee’s sale or foreclosure proceedings against all such collateral securing the Obligations (including the Mortgaged Property), which action may be brought or consolidated in the courts of, or sale conducted in, any county in which any of such collateral is located. Grantor acknowledges that the right to maintain a consolidated trustee’s sale or foreclosure action is a specific inducement to Beneficiary to extend the indebtedness borrowed pursuant to or guaranteed by the Second Lien Security Documents, and Grantor expressly and irrevocably waives any objections to the commencement or consolidation of the foreclosure proceedings in a single action and any objections to the laying of venue or based on the grounds of forum non conveniens which it may now or hereafter have. Grantor further agrees that if Trustee or Beneficiary shall be prosecuting one or more foreclosure or other proceedings against a portion of the Mortgaged Property or against any collateral other than the Mortgaged Property, which collateral directly or indirectly
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secures the Obligations, or if Beneficiary shall have obtained a judgment of foreclosure and sale or similar judgment against such collateral (or, in the case of a trustee’s sale, shall have met the statutory requirements therefor with respect to such collateral), then, whether or not such proceedings are being maintained or judgments were obtained in or outside the State in which the Premises are located, Beneficiary may commence or continue any foreclosure proceedings and exercise its other remedies granted in this Deed of Trust against all or any part of the Mortgaged Property and Grantor waives any objections to the commencement or continuation of a foreclosure of this Deed of Trust or exercise of any other remedies hereunder based on such other proceedings or judgments, and waives any right to seek to dismiss, stay, remove, transfer or consolidate either any action under this Deed of Trust or such other proceedings on such basis. The commencement or continuation of proceedings to sell the Mortgaged Property in a trustee’s sale to foreclose this Deed of Trust, or the exercise of any other rights hereunder or the recovery of any judgment by Beneficiary in any such proceedings or the occurrence of any sale by the Trustee in any such proceedings shall not prejudice, limit or preclude Beneficiary’s right to commence or continue one or more trustee’s sales, foreclosure or other proceedings or obtain a judgment against (or, in the case of a trustee’s sale, to meet the statutory requirements for, any such sale of) any other collateral (either in or outside the State in which the Premises are located) which directly or indirectly secures the Obligations, and Grantor expressly waives any objections to the commencement of, continuation of, or entry of a judgment in such other sales or proceedings or exercise of any remedies in such sales or proceedings based upon any action or judgment connected to this Deed of Trust, and Grantor also waives any right to seek to dismiss, stay, remove, transfer or consolidate either such other sales or proceedings or any sale or action under this Deed of Trust on such basis. It is expressly understood and agreed that to the fullest extent permitted by law, Beneficiary may, at its election, cause the sale of all collateral that is the subject of a single foreclosure action at either a single sale or at multiple sales conducted simultaneously and take such other measures as are appropriate in order to effect the agreement of the parties to dispose of and administer all collateral securing the Obligations (directly or indirectly) in the most economical and least time-consuming manner.
| 18. | SUCCESSORS AND ASSIGNS |
All covenants of Grantor contained in this Deed of Trust are imposed solely and exclusively for the benefit of Beneficiary, and its successors and assigns, and no other person or entity shall have standing to require compliance with such covenants or be deemed, under any circumstances, to be a beneficiary of such covenants, any or all of which may be freely waived in whole or in part by Beneficiary at any time if in the sole discretion of either of them such a waiver is deemed advisable. All such covenants of Grantor shall run with the land and bind Grantor, the successors and assigns of Grantor (and each of them) and all subsequent owners, encumbrances and tenants of the Mortgaged Property, and shall inure to the benefit of Trustee and Beneficiary and their respective successors and assigns. The word “Grantor” shall be construed as if it read “Grantors” whenever the sense of this Deed of Trust so requires and if there shall be more than one Grantor, the obligations of the Grantors shall be joint and several.
| 19. | NO WAIVERS, ETC. |
Any failure by Beneficiary to insist upon the strict performance by Grantor of any of the terms and provisions of this Deed of Trust shall not be deemed to be a waiver of any of the terms
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and provisions hereof, and Beneficiary, notwithstanding any such failure, shall have the right thereafter to insist upon the strict performance by Grantor of any and all of the terms and provisions of this Deed of Trust to be performed by Grantor. Beneficiary may release, regardless of consideration and without the necessity for any notice to or consent by the holder of any subordinate lien on the Mortgaged Property, any part of the security held for the obligations secured by this Deed of Trust without, as to the remainder of the security, in any way impairing or affecting the lien of this Deed of Trust or the priority of such lien over any subordinate lien or deed of trust.
| 20. | GOVERNING LAW, ETC. |
This Deed of Trust shall be governed by and construed and interpreted in accordance with the laws of the State of Texas, except that Grantor expressly acknowledges that by their respective terms the Second Lien Security Documents (unless otherwise specified therein) shall be governed and construed in accordance with the laws of the State of New York.
| 21. | DUTY OF BENEFICIARY; AUTHORITY OF BENEFICIARY |
(a) Beneficiary’s sole duty with respect to the custody, safekeeping and physical preservation of the Mortgaged Property that is in its possession, or otherwise, shall be to deal with it in the same manner as Beneficiary deals with similar property for its own account. Neither Beneficiary, any Second Lien Secured Party nor any of their respective officers, directors, employees or agents shall be liable for failure to demand, collect or realize upon any of the Mortgaged Property or for any delay in doing so or shall be under any obligation to sell or otherwise dispose of any Mortgaged Property upon the request of Grantor or any other Person or to take any other action whatsoever with regard to the Mortgaged Property or any part thereof. The powers conferred on Beneficiary and the Second Lien Secured Parties hereunder are solely to protect Beneficiary’s and the Second Lien Secured Parties’ interests in the Mortgaged Property and shall not impose any duty upon Beneficiary or any Second Lien Secured Party to exercise any such powers. BENEFICIARY AND THE SECOND LIEN SECURED PARTIES SHALL BE ACCOUNTABLE ONLY FOR AMOUNTS THAT THEY ACTUALLY RECEIVE AS A RESULT OF THE EXERCISE OF SUCH POWERS, AND NEITHER THEY NOR ANY OF THEIR OFFICERS, DIRECTORS, EMPLOYEES OR AGENTS SHALL BE RESPONSIBLE TO GRANTOR FOR ANY ACT OR FAILURE TO ACT HEREUNDER, EXCEPT FOR THEIR OWN GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.
(b) Grantor acknowledges that the rights and responsibilities of Beneficiary under this Deed of Trust with respect to any action taken by Beneficiary or the exercise or non-exercise by Beneficiary of any option, voting right, request, judgment or other right or remedy provided for herein or resulting or arising out of this Deed of Trust shall, as between Beneficiary and any Second Lien Secured Party, be governed by the Indenture or appropriate Additional Second Lien Agreement, as applicable, and by such other agreements with respect thereto as may exist from time to time among them, but, as between Beneficiary and Grantor, Beneficiary shall be conclusively presumed to be acting as agent for the Second Lien Secured Parties with full and valid authority so to act or refrain from acting, and Grantor shall be under no obligation, or entitlement, to make any inquiry respecting such authority.
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| 22. | LAST DOLLARS SECURED; PRIORITY |
To the extent that this Deed of Trust secures only a portion of the indebtedness owing or that may be owing by Grantor to any Second Lien Secured Party, the parties agree that any payments or repayments of such indebtedness shall be and be deemed to be applied first to the portion of the indebtedness that is not secured hereby, it being the parties’ intent that the portion of the indebtedness last remaining unpaid shall be secured hereby. If at any time this Deed of Trust shall secure less than all of the principal amount of the Obligations, it is expressly agreed that any repayments of the principal amount of the Obligations shall not reduce the amount of the lien of this Deed of Trust until the lien amount shall equal the principal amount of the Obligations outstanding.
| 23. | ENFORCEMENT EXPENSES; INDEMNIFICATION |
(a) Grantor agrees to pay any and all reasonable and documented out-of-pocket costs and expenses (including all reasonable and documented fees, disbursements and other charges of one firm of counsel, and, if necessary, one firm of regulatory counsel and/or one firm of local counsel in each appropriate jurisdiction, in each case to Beneficiary (and, in the case of an actual or perceived conflict of interest where the Person affected by such conflict informs the Issuer of such conflict and thereafter, retains its own counsel, of another firm of counsel for such affected Person)) that may be paid or incurred by any Second Lien Secured Party in enforcing, or obtaining advice of counsel in respect of, any rights with respect to, or collecting, any or all of the Obligations and/or enforcing any rights with respect to, or collecting against, such Grantor under this Deed of Trust.
(b) Grantor agrees to pay, and to save Beneficiary and the Second Lien Secured Parties harmless from, any and all liabilities with respect to, or resulting from any delay in paying, any and all stamp, excise, sales or other taxes which may be payable or determined to be payable with respect to any of the Mortgaged Property or in connection with any of the transactions contemplated by this Deed of Trust.
(c) Grantor agrees to pay, and to save Beneficiary harmless from, any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever with respect to the execution, delivery, enforcement, performance and administration of this Deed of Trust to the extent Issuer would be required to do so pursuant to Section 7.07 of the Indenture,AND SUBJECT TO THE PARAGRAPH BELOW, WHETHER OR NOT CAUSED BY, OR ARISING IN WHOLE OR IN PART OUT OF, THE COMPARATIVE, CONTRIBUTORY, OR SOLE NEGLIGENCE OF BENEFICIARY OR THE SECOND LIEN SECURED PARTIES; PROVIDED, HOWEVER, NOTWITHSTANDING ANYTHING IN SECTION 7.07 OF THE INDENTURE TO THE CONTRARY, BENEFICIARY MAY BE INDEMNIFIED FOR MATTERS CAUSED BY OR THAT ARISE OUT OF THE NEGLIGENCE OF BENEFICIARY UNDER BUT SUBJECT TO THE PROVISIONS OF THIS SECTION 23(c).
In no event shall Beneficiary be responsible or liable for special, indirect or consequential loss or damage of any kind whatsoever, irrespective of whether Beneficiary has been informed of
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the likelihood of such loss or damages and regardless of the form of action. Neither Issuer, Parent Guarantor, nor any Subsidiary Guarantor shall have any obligation hereunder to Beneficiary or any of its Related Parties (the “Indemnified Parties”) with respect to indemnified liabilities to the extent it has been determined by a final non-appealable judgment of a court of competent jurisdiction to have resulted from (A) the gross negligence, bad faith or willful misconduct of any Indemnified Party (other than trustees and advisors), (B) a breach of the obligations of any Indemnified Party (other than trustees and advisors) under the Second Lien Security Documents or (C) disputes not involving an act or omission of any of Issuer, Parent Guarantor, or any Subsidiary Guarantor or any of their respective Affiliates and that is brought by any Indemnified Party against any other Indemnified Party.
(d) The agreements in this Section 23 shall survive repayment of the Obligations and all other amounts payable under the Second Lien Security Documents.
| 24. | RELEASE |
If any of the Mortgaged Property shall be sold, transferred or otherwise disposed of by any Grantor in a transaction permitted by the Second Lien Security Documents and the Net Proceeds are applied in accordance with any applicable requirement (if any) of the Indenture, then Beneficiary, at the request and sole expense of such Grantor, shall execute and deliver to such Grantor all releases or other documents reasonably necessary or desirable for the release of the Liens created hereby on such Mortgaged Property. The Grantor shall deliver to Beneficiary, at least five Business Days prior to the date of the proposed release, a written request for release identifying the sale or other disposition in reasonable detail, including the price thereof and any expenses in connection therewith, together with a certification by the Grantor stating that such transaction is in compliance with, and permitted by, the Second Lien Security Documents. In addition, upon the execution by Grantor of an easement, right-of-way or other real property interest that constitutes a Permitted Lien pursuant to clause (5) of the definition of Permitted Liens in the Indenture (a “Permitted Real Property Interest”), Beneficiary will subordinate the Liens created hereby to the rights of third parties with respect to such Permitted Real Property Interest.
| 25. | SUBSTITUTE TRUSTEE |
In case of the resignation of the Trustee, or the inability (through death or otherwise), refusal or failure of the Trustee to act, or at the option of Beneficiary or the holder(s) of a majority of the Obligations for any other reason (which reason need not be stated), a substitute Trustee (“Substitute Trustee”) may be named, constituted and appointed by Beneficiary or the holder(s) of a majority of the Obligations, without other formality than an appointment and designation in writing, which appointment and designation shall be full evidence of the right and authority to make the same and of all facts therein recited, and this conveyance shall vest in the Substitute Trustee the title, powers and duties herein conferred on the Trustee originally named herein, and the conveyance of the Substitute Trustee to the purchaser(s) at any sale of the Mortgaged Property of any part thereof shall be equally valid and effective. The right to appoint a Substitute Trustee shall exist as often and whenever from any of said causes, the Trustee, original or Substitute Trustee, resigns or cannot, will not or does not act, or Beneficiary or the holder(s) of a majority of the Obligations desires to appoint a new Trustee. No bond shall ever
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be required of the Trustee, original or Substitute Trustee. The recitals in any conveyance made by the Trustee, original or Substitute, shall be accepted and construed in court and elsewhere as prima facie evidence and proof of the facts recited, and no other proof shall be required as to the request by Beneficiary or the holders(s) of a majority of Obligations to the Trustee to enforce this Deed of Trust, or as to the notice of or holding of the sale, or as to any particulars thereof, or as to the resignation of the Trustee, original or Substitute, or as to the inability, refusal or failure of the Trustee, original or Substitute Trustee, to act, or as to the election of Beneficiary or the holder(s) of a majority of the Obligations to appoint a new Trustee, or as to appointment of a Substitute Trustee, and all prerequisites of said sale shall be presumed to have been performed; and each sale made under the powers herein granted shall be a perpetual bar against Grantor and the heirs, personal representatives, successors and assigns of Grantor. Trustee, original or substitute, is hereby authorized and empowered to appoint any one or more persons as attorney-in-fact to act as Trustee under it and in its name, place and stead in order to take any actions that Trustee is authorized and empowered to do hereunder, such appointment to be evidenced by an instrument signed and acknowledged by said Trustee, original or Substitute Trustee; and all acts done by said attorney-in-fact shall be valid, lawful and binding as if done by said Trustee, original or Substitute Trustee, in person.
| 26. | INDEMNIFICATION OF TRUSTEE |
EXCEPT FOR GROSS NEGLIGENCE OR WILLFUL MISCONDUCT, TRUSTEE SHALL NOT BE LIABLE FOR ANY ACT OR OMISSION OR ERROR OF JUDGMENT. TRUSTEE MAY RELY ON ANY DOCUMENT BELIEVED BY IT IN GOOD FAITH TO BE GENUINE. ALL MONEY RECEIVED BY TRUSTEE SHALL, UNTIL USED OR APPLIED AS HEREIN PROVIDED, BE HELD IN TRUST, AND TRUSTEE SHALL NOT BE LIABLE FOR INTEREST THEREON. GRANTOR SHALL INDEMNIFY TRUSTEE AGAINST ALL LIABILITY AND EXPENSES THAT IT MAY INCUR IN THE PERFORMANCE OF ITS DUTIES HEREUNDER EXCEPT FOR GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.
| 27. | ACCEPTANCE BY TRUSTEE |
Trustee accepts its duties and obligations under this Deed of Trust and the Second Lien Security Documents when this Deed of Trust, duly executed and acknowledged, is made a public record as provided by law.
| 28. | ENTIRE AGREEMENT |
THIS DEED OF TRUST AND THE OTHER SECOND LIEN SECURITY DOCUMENTS IN EFFECT AS OF THE DATE HEREOF REPRESENT THE FINAL AGREEMENT AS OF THE DATE HEREOF BETWEEN THE PARTIES RELATING TO THE FINANCING TRANSACTION DESCRIBED IN THE INDENTURE AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
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| 29. | MATURITY OF OBLIGATIONS |
The maturity date of the Obligations under the Indenture is April 1, 2021. The maturity date of any Obligations under any Additional Second Lien Agreement, if different from the foregoing date, shall be specified in a supplement to this Deed of Trust.
| 30. | EVIDENCE OF INSURANCE |
Notwithstanding any provision herein or in the Indenture or any other Second Lien Security Document to the contrary, pursuant to Section 549.054 of the Texas Insurance Code, Grantor shall not be required to furnish evidence of insurance more than fifteen (15) days prior to the termination date of an existing insurance policy, and pursuant to Section 549.052 of the Texas Insurance Code, Grantor shall not be required to obtain an insurance policy from or through a particular agent, insurer or other person or a particular type or class of agent, insurer or other person.
| 31. | FUTURE ADVANCES |
This Deed of Trust is given for the purpose of creating a lien on the Mortgaged Property and expressly used to secure not only the existing Obligations, but also (i) all extensions, renewals, modifications or re-amortizations of the Obligations, all increases or additions to the Obligations, all loans and future advances and re-advances made by any existing or future Second Lien Secured Party to the Grantor or the Issuer pursuant to the Second Lien Security Documents, including any such advances evidenced and/or secured by Additional Notes and supplements to the Indenture and/or any Additional Second Lien Agreement, and (ii) future advances, whether such advances are obligatory or to be made at the option of any Second Lien Secured Party or otherwise, to the same extent as if such future advances were made, whether under the Indenture, any of the other Second Lien Security Documents or otherwise on the date of the execution of this Deed of Trust, and creates a lien for all advances regardless of who is the owner of the Mortgaged Property at the time such advances are made.
| 32. | MULTIPLE GRANTORS |
If this Deed of Trust is executed by two or more Grantors, each Exhibit shall include a designation identifying which Grantor owns an interest in each tract of Land, each Mortgaged Lease and each Easement Right. The representations, warranties, and covenants made by a Grantor herein shall apply to each Grantor as to its respective Mortgaged Property.
| 33. | ONCOR SEPARATENESS |
(a) Beneficiary, on behalf of itself and the Second Lien Secured Parties, acknowledges (i) the legal separateness of the Issuer and the Grantor from the Subsidiaries of Energy Future Intermediate Holding Company LLC, a Delaware limited liability company (the “Oncor Subsidiaries”), (ii) that the lenders under the Oncor Credit Facility and the noteholders under the Oncor Subsidiaries’ indentures have likely advanced funds thereunder in reliance upon the separateness of the Oncor Subsidiaries from the Issuer and the Grantors, (iii) that the Oncor Subsidiaries have assets and liabilities that are separate from those of Parent Guarantor and its Subsidiaries, (iv) that the Obligations owing under the Second Lien Security Documents are
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obligations and liabilities of the Issuer and the Guarantors only, and are not the obligations or liabilities of the Oncor Subsidiaries, (v) that the Second Lien Secured Parties shall look solely to the Issuer, the Guarantors and their assets, and not to any assets, or to the pledge of any assets, owned by the Oncor Subsidiaries, for the repayment of any amounts payable pursuant to the Second Lien Security Documents and for satisfaction of any other Obligations owing to the Second Lien Secured Parties under the Second Lien Security Documents, and (vi) that none of the Oncor Subsidiaries shall be personally liable to the Second Lien Secured Parties for any amounts payable, or any other liability, under the Second Lien Security Documents.
(b) Beneficiary, on behalf of itself and the Second Lien Secured Parties, shall not (i) initiate any legal proceeding to procure the appointment of an administrative receiver, or (ii) institute any bankruptcy, reorganization, insolvency, winding up, liquidation, or any like proceeding under applicable law, against any of the Oncor Subsidiaries, or against any of the Oncor Subsidiaries’ assets. Beneficiary, on behalf of itself and the Second Lien Secured Parties, acknowledges and agrees that each of the Oncor Subsidiaries is a third party beneficiary of the forgoing covenant and shall have the right to specifically enforce such covenant in any proceeding at law or in equity.
| 34. | MORTGAGED LEASES |
(a)Representations, Warranties and Covenants. Grantor represents and warrants to Beneficiary that, with respect to each Mortgaged Lease, (i) the Mortgaged Lease is unmodified and in full force and effect, (ii) all rent and other charges therein have been paid to the extent they are payable to the date hereof, (iii) Grantor enjoys the quiet and peaceful possession of the property demised thereby, (iv) Grantor is not in default under any of the terms thereof and there are no circumstances which, with the passage of time or the giving of notice or both, would constitute an event of default thereunder, and (v) the lessor thereunder is not in default under any of the terms or provisions thereof on the part of the lessor to be observed or performed (but this statement is made for the benefit of and may only be relied upon by Beneficiary and the Second Lien Secured Parties) except in the case of each of the matters described in clauses (i) through (v) of this sentence, where the failure of such statements to be true could not reasonably be expected to have a Material Adverse Effect. Grantor shall promptly pay, when due and payable, the rent and other charges payable pursuant to the Mortgaged Lease, and will timely perform and observe all of the other terms, covenants and conditions required to be performed and observed by Grantor as lessee under the Mortgaged Lease. Grantor shall notify Beneficiary in writing of any default by Grantor in the performance or observance of any terms, covenants or conditions on the part of Grantor to be performed or observed under the Mortgaged Lease within ten (10) days after Grantor knows of such default. Grantor shall, promptly following the receipt thereof, deliver a copy of any notice of default given to Grantor by the lessor pursuant to the Mortgaged Lease and promptly notify Beneficiary in writing of any default by the lessor in the performance or observance of any of the terms, covenants or conditions on the part of the lessor to be performed or observed thereunder. Unless required under the terms of the Mortgaged Lease, except as set forth in the Indenture, Grantor shall not, without the prior written consent of Beneficiary (which may be granted or withheld in Beneficiary’s sole and absolute discretion) (A) terminate, or surrender the Mortgaged Lease, or (B) enter into any modification of the Mortgaged Lease which materially impairs the practical realization of the security interests granted by this Deed of Trust, and any such attempted termination, modification or surrender
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without Beneficiary’s written consent shall be void. Grantor shall, within thirty (30) days after written request from Beneficiary, use commercially reasonable efforts to obtain from the lessor and deliver to Beneficiary a certificate setting forth the name of the tenant thereunder and stating that the Mortgaged Lease is in full force and effect, is unmodified or, if the Mortgaged Lease has been modified, the date of each modification (together with copies of each such modification), that no notice of termination thereof has been served on Grantor, stating that to the best of lessor’s knowledge, no default or event which with notice or lapse of time (or both) would become a default is existing under the Mortgaged Lease, stating the date to which rent has been paid, and specifying the nature of any defaults, if any, and containing such other statements and representations as may be reasonably requested by Beneficiary.
(b)No Merger; Acquisition; Power of Attorney. So long as any of the Obligations remain unpaid or unperformed, the fee title to and the leasehold estate in the premises subject to each Mortgaged Lease shall not merge but shall always be kept separate and distinct notwithstanding the union of such estates in the lessor or Grantor, or in a third party, by purchase or otherwise. If Grantor acquires the fee title or any other estate, title or interest in the property demised by the Mortgaged Lease, or any part thereof, the lien of this Deed of Trust shall attach to, cover and be a lien upon such acquired estate, title or interest and the same shall thereupon be and become a part of the Mortgaged Property with the same force and effect as if specifically encumbered herein. Grantor agrees to execute all instruments and documents that Beneficiary may reasonably require to ratify, confirm and further evidence the lien of this Deed of Trust on the acquired estate, title or interest. Furthermore, Grantor hereby appoints Beneficiary as its true and lawful attorney-in-fact to execute and deliver, following an Event of Default, all such instruments and documents in the name and on behalf of Grantor. This power, being coupled with an interest, shall be irrevocable as long as any portion of the Obligations remains unpaid.
(c)New Leases. If the Mortgaged Lease shall be terminated prior to the natural expiration of its term due to default by Grantor or any tenant thereunder, and if, pursuant to the provisions of the Mortgaged Lease, Beneficiary or its designee shall acquire from the lessor a new lease of the premises subject to the Mortgaged Lease, Grantor shall have no right, title or interest in or to such new lease or the leasehold estate created thereby, or renewal privileges therein contained.
(d)No Assignment. Notwithstanding anything to the contrary contained herein, this Deed of Trust shall not constitute an assignment of any Mortgaged Lease within the meaning of any provision thereof prohibiting its assignment and Beneficiary shall have no liability or obligation thereunder by reason of its acceptance of this Deed of Trust. Beneficiary shall be liable for the obligations of the tenant arising out of any Mortgaged Lease for only that period of time for which Beneficiary is in possession of the premises demised thereunder or has acquired, by foreclosure or otherwise, and is holding all of Grantor’s right, title and interest therein.
This Deed of Trust has been duly executed by Grantor as of the date first above written and is intended to be effective as of such date.
[Remainder of Page Intentionally Left Blank.
Signature Page Follows.]
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[SAMPLE SIGNATURE PAGE]
LUMINANT GENERATION COMPANY LLC, a Texas limited liability company | ||
By: |
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Name: |
| |
Title: |
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THE STATE OF TEXAS | § | |||
| § | ||||
COUNTY OF DALLAS | § |
This instrument was acknowledged before me on December , 2010 by (name of officer), (title of officer) of [LUMINANT GENERATION COMPANY LLC, a Texas limited liability company), on behalf of said limited liability company.
| ||
Notary Public in and for The State of Texas | ||
My Commission Expires: |
| |
[Signature Page – Second Deed of Trust, Assignment of Leases and Rents, Security Agreement and Fixture Filing]
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EXHIBIT A
Owned Land
A-1
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EXHIBIT B
Mortgaged Leases and Mortgaged Leased Land
B-1
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EXHIBIT C
Easements and Easement Land
C-1
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EXHIBIT D
Certificates of Adjudication and Other Water Rights
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Exhibit 10(c)
AMENDMENT TO THE ENERGY FUTURE HOLDINGS CORP.
EXECUTIVE CHANGE IN CONTROL POLICY
THIS AMENDMENT to the Energy Future Holdings Corp. Executive Change in Control Policy (the “Policy”), originally effective as of May 20, 2005, is made by Energy Future Holdings Corp. (the “Company”) this 20th day of December 2010, to be effective as of January 1, 2009.
WITNESSETH:
WHEREAS, the Company desires to amend the Policy to clarify the applicability of the exemption from Section 409A of the Internal Revenue Code of 1986, as amended for certain separation pay plans and, where necessary, to comply with Code Section 409A and the regulations and other guidance promulgated thereunder; and
WHEREAS, the Company has the sole discretion to change, modify, alter or amend the Policy at any time;
NOW, THEREFORE, in consideration of the premises contained herein, the Company shall amend the Policy as follows, effective as of January 1, 2009.
1. Subsection a, of Section 3, entitled “Available Benefits”, is hereby amended in its entirety to read as follows:
“a.Cash Severance Payment. Eligible Executives will receive a one-time lump sum cash severance payment in an amount equal to a multiple of the aggregate of: (i) the Eligible Executive’s annualized base salary in effect immediately before the termination or resignation, or the Executive’s annualized base salary in effect as of the effective date of the Change in Control, whichever is greater; plus (ii) the Eligible Executive’s target annual incentive award for the year of the termination or resignation. The multiple will be determined as set forth in the following chart, and will be based on the Eligible Executive’s position with the Company immediately prior to the termination or resignation, or the Eligible Executive’s position as of the effective date of the Change in Control, whichever position is more senior:
Position | Multiple of Base Salary + Target Annual Incentive | |
| Chief Executive Officer | 3x | |
| Member of Senior Leadership Team | 2x | |
| Member of Leadership Team | 1x | |
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The severance payment will be made within the 90-day period following the Eligible Executive’s termination of employment; provided that if the 90-day period begins in one taxable year of the Eligible Executive and ends in a subsequent taxable year of the Eligible Executive, such payment shall be made in the subsequent taxable year. Notwithstanding the foregoing, if the Eligible Executive is a “specified employee” within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended, the severance payment will, to the extent required under Code Section 409A, be made on the first business day following the expiration of six (6) months following the date of the Eligible Executive’s termination of employment.
The severance payment will be subject to all applicable tax withholdings and will also be reduced by the amount of any obligations which the Eligible Executive owes to the Company. Such obligations may include, but are not limited to, some or all of the following:
(1) The entire balance, if any, that the Eligible Executive owes under the Company’s appliance purchase plan, energy conservation program or employee relocation plan; and
(2) Any balance on Company-issued or sponsored travel or credit cards or any other expenses or payments for which the Company should be reimbursed.”
2. Subsection c, of Section 3, entitled “Available Benefits”, is hereby amended in its entirety to read as follows:
“c.Health Care Benefits. Eligible Executives will be eligible for continued health care coverage under the Company’s health care plans for the applicable COBRA period. The required contribution by the Eligible Executive for such continued coverage will be the applicable employee rate, for the period
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shown in the following table, unless and until the end of such period, or until the Eligible Executive becomes eligible for coverage for a particular type of benefit through employment with another employer, at which time the required contribution for continuing such benefit coverage hereunder shall be the applicable COBRA rate for such benefit. The period of continued health care coverage provided for herein shall run concurrently with the Eligible Executive’s available COBRA coverage period.
Position | Period of Subsidized Premium for Health Care Coverage | |
| Chief Executive Officer of EFH | 18 months | |
| Member of Senior Leadership Team | 18 months | |
| Member of Leadership Team | 1 year | |
If an Eligible Executive who is the Chief Executive Officer of EFH or a member of the Senior Leadership Team is covered under the Company’s health care plans through the end of such eighteen (18) month period, then such Eligible Executive shall receive an additional payment on the last day of such eighteen (18) month period, in an amount equal to the monthly cost of such coverage (determined as of such date) for the period provided in the following table:
Position | Period of Subsidized Premium for Health Care Coverage | |
| Chief Executive Officer of EFH | 18 months | |
| Member of Senior Leadership Team | 6 months | |
Such payment shall be made in a lump sum.”
3. Subsection g, of Section 3, entitled “Available Benefits”, is hereby amended in its entirety to read as follows:
“g.Tax Gross-up. If any payment, distribution or provision of a benefit hereunder (a “Payment”) would be subject to an excise tax pursuant to Sections 280G and 4999 of the Internal Revenue Code of 1986, as amended (“Code”), or any interest or penalties with respect to such excise or other additional tax (such excise tax, together with any such interest or penalties, are hereinafter collectively referred to as the “Excise Tax”), the Company, Parent Corporation, Surviving Corporation or any subsidiary thereof, as applicable (for purposes of this Section, all such entities are referred to as the “Surviving
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Company”) shall pay to the Eligible Executive an additional payment (“Gross-up Payment”) in an amount such that, after payment by the Eligible Executive of all taxes, including any income taxes and Excise Taxes imposed on any Gross-up Payment (including any interest or penalties imposed with respect to such taxes), the Eligible Executive retains an amount of the Gross-up Payment equal to the Excise Tax imposed upon the Payments. Notwithstanding the foregoing, however, if the aggregate value of the Payments (as determined in accordance with Code Section 28OG) is less than 110% of the product (such product to be referred to herein as the “Excise Tax Threshold”) of three times the Eligible Executive’s “base amount” (as such term is defined in Code Section 280G), then the Eligible Executive shall not be entitled to a Gross-up Payment, and the Payments shall be reduced so that their aggregate value is equal to $1.00 less than the Excise Tax Threshold, first, by reducing the Health Care Benefits provided following the expiration of the 18-month COBRA coverage period, if applicable and, second, by reducing the Cash Severance Payment. The Surviving Company will coordinate with the Eligible Executive to make an initial determination as to whether a Gross-up Payment is required and the amount of any such Gross-up Payment. The Eligible Executive shall notify the Surviving Company in writing of any claim by the Internal Revenue Service which, if successful, would require a Gross-up Payment (or a Gross-up Payment in excess of that initially determined). The Surviving Company shall notify the Eligible Executive in writing at least ten (10) business days prior to the due date of any response required with respect to such claim if it plans to contest the claim. If the Surviving Company decides to contest such claim, the Eligible Executive shall cooperate with the Surviving Company in such action; provided, however, the Surviving Company shall bear and pay all costs and expenses (including additional interest and penalties) incurred in connection with such action and shall indemnify and hold the Eligible Executive harmless, on an after-tax basis, for any Excise Tax or income lax, including interest and penalties with respect thereto, imposed as a result of the Surviving Company’s action. If, as a result of the Surviving Company’s action with respect to any such claim, the Eligible Executive receives a refund of any amount paid by the Surviving Company with respect to such claim, the Eligible Executive shall promptly pay such refund to the Surviving Company. If the Surviving Company fails to timely notify the Eligible Executive whether it will contest such claim or the Surviving Company determines not to contest such claim, then the Surviving Company shall immediately pay to the Eligible Executive the portion of such claim, if any, which it has not previously paid to the Eligible Executive.
Any Gross-Up Payment, as determined pursuant to this Section, shall be paid by the Surviving Company to the Executive within five days of the determination of the amount of the Gross-Up Payment; provided that, the Gross-Up Payment shall in all events be paid no later than the end of the Executive’s taxable year next following the Executive’s taxable year in which the Excise Tax (and any income or other related taxes or interest or penalties thereon) on a Payment are remitted to the Internal Revenue Service or any other applicable
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taxing authority or, in the case of amounts relating to a claim that does not result in the remittance of any federal, state, local and foreign income, excise, social security and other taxes, the calendar year in which the claim is finally settled or otherwise resolved. Notwithstanding any other provision of this Section, the Surviving Company may, in its sole discretion, withhold and pay over to the Internal Revenue Service or any other applicable taxing authority, for the benefit of the Executive, all or any portion of any Gross-Up Payment, and the Executive hereby consents to such withholding.”
4. Subsection h, of Section 3, entitled “Available Benefits”, is hereby added to read as follows:
“h.Administrative Delay in Payment. Benefits hereunder shall be paid on the date specified in accordance with the foregoing provisions of this Section 3; provided that, in the case of administrative necessity, the payment of such benefits may be delayed up to the last day of the calendar year in which payment would otherwise be made or, if later, the 15th day of the third calendar month following the date on which payment would otherwise be made.”
5. Section 4, entitled “Agreement and Release”, is hereby amended in its entirety to read as follows:
“4.Agreement and Release. Except as otherwise provided under Section 9, each Eligible Executive’s eligibility for any of the benefits described herein will be subject to, and conditioned upon, the Surviving Company’s receipt of an executed Agreement and Release, in the form provided by the Surviving Company, on or prior to the ninetieth (90th) day following the Eligible Executive’s termination of employment.”
6. Section 7, entitled “Change in Control”, is hereby amended in its entirety to read as follows:
“7.Change in Control. For purposes of this Policy, the term “Change in Control” shall mean the occurrence of any one or more of the following events: (i) the sale (or combined sales within the 12-month period ending on the date of the most recent sale) of all or substantially all of the consolidated assets or capital stock of the Company, or an Affiliate, to a person (or group of persons acting in concert) who is not an Affiliate of the Company or any member of the Sponsor Group; (ii) a merger, recapitalization or other sale by the Company, any member of the Sponsor Group or its Affiliates to a person (or group of persons acting in concert) of the common stock of the Company that results in more than 50% of the common stock of the Company (or any resulting company after a merger (the “Surviving Corporation”)) being held by a person (or group of persons acting in concert) who is not an Affiliate of the Company or any member of the Sponsor Group; or (iii) a merger, recapitalization or other sale (or combined sales within the 12-month period ending on the date of the most recent sale) by the Company, any member of the Sponsor Group or their Affiliates of the common stock of the
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Company, after which the Sponsor Group owns less than 20% of the common stock of, and has the ability to appoint less than a majority of the directors to the Board of Directors (“the Board”) of, the Company (or any Surviving Corporation) and at least one person (or group of persons acting in concert) has acquired 30% or more of such common stock; and with respect to any of the events described in clauses (i) through (ii) above, such event results in any person (or group of persons acting in concert) gaining control of more seats on the Board than the Sponsor Group.
Notwithstanding any provision of this Policy to the contrary, for purposes of this Section, the term “Affiliate” shall have the meaning ascribed to it under applicable provisions of Section 409A of the Code and, for purposes of clause (i) shall include any such entity for whom the Eligible Executive is performing services at the time of the Change in Control event, an entity that is liable for the payment of the benefits hereunder, or an entity that is a majority shareholder of the foregoing entities. The determination of whether a Change in Control has occurred under this Policy shall be made by EFH in accordance with the provisions of Code Section 409A and the regulations promulgated thereunder.”
7. Section 10, entitled “Termination of Employment”, is hereby added to read as follows:
“10.Termination of Employment. Except to the extent otherwise provided in Section 9, no benefits will be paid until the Eligible Executive has experienced a termination of employment. For purposes of this Policy, an Eligible Executive shall be treated as having experienced a termination of employment on the date on which the Surviving Company and the Eligible Executive reasonably anticipate that no further services will be performed by the Eligible Executive for the Surviving Company or any person with whom the Surviving Company would be considered a single employer under Treasury Regulations §1.409A-1(h)(3).”
8. Section 11, entitled “Compliance with Tax Laws”, is hereby added to read as follows:
“11.Compliance with Tax Laws. Notwithstanding any provision in this Policy to the contrary, if any portion of this Policy does not constitute a separation pay plan exempt from the requirements of Code Section 409A and an ambiguity exists with respect to any benefit under this Policy that constitutes a deferral of compensation under a nonqualified deferred compensation plan, as such term is described under Section 409A of the Code, the Company shall interpret the Policy in such manner as it, in its sole and absolute discretion, deems necessary to comply with the requirements of Section 409A of the Code and applicable guidance published in the Internal Revenue Bulletin.”
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IN WITNESS WHEREOF, and as conclusive evidence of the adoption of the foregoing instrument comprising an Amendment to the Energy Future Holdings Corp. Executive Change in Control Policy, Energy Future Holdings Corp. has caused these presents to be duly executed in its name and on its behalf this 20th day of December, 2010.
| By: | /s/ RICHARD LANDY | |
| Richard Landy | ||
| Executive Vice President, Human Resources |
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Exhibit 10(f)
AMENDMENT TO THE ENERGY FUTURE HOLDINGS CORP. 2005
EXECUTIVE SEVERANCE PLAN AND SUMMARY PLAN DESCRIPTION
THIS AMENDMENT to the Energy Future Holdings Corp. 2005 Executive Severance Plan and Summary Plan Description (the “Plan”), originally effective as of May 20, 2005, is made by Energy Future Holdings Corp. (the “Company”) this 10th day of December 2010, to be effective as of January 1, 2009.
WITNESSETH:
WHEREAS, the Company desires to amend the Plan to clarify the applicability of the exemption from Section 409A of the Internal Revenue Code of 1986, as amended for certain separation pay plans and, where necessary, to comply with Code Section 409A and the regulations and other guidance promulgated thereunder; and
WHEREAS, the Company has the sole discretion to change, modify, alter or amend the Plan at any time;
NOW, THEREFORE, in consideration of the premises contained herein, the Company shall amend the Plan as follows, effective as of January 1, 2009.
1. The Section entitled “Eligibility to Participate In the Plan” shall be amended by adding the following questions and answers to the end to read as follows:
| “- | When will I be treated as having terminated employment under this Executive Severance Plan? |
For purposes of this Executive Severance Plan, you are treated as having experienced a termination of employment on the date on which you and the Company reasonably anticipate that you will perform no further services for the Company or any affiliate of the Company.
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| - | What is Section 409A of the Internal Revenue Code and when will it apply to my benefits under this Executive Severance Plan? |
Section 409A of the Code governs benefits that constitute a “deferral of compensation” under a nonqualified deferred compensation plan, as described thereunder. For benefits subject to Code Section 409A, the Executive Severance Plan must be designed and operated in accordance with the requirements of Code Section 409A. In the event that all or any portion of the benefits under this Executive Severance Plan do not satisfy the requirements of Code Section 409A, either in form or operation, you may be required to pay an excise tax.
To the extent that any portion of this Executive Severance Plan does not constitute a separation pay plan exempt from the requirements of Code Section 409A, and an ambiguity exists with respect to any benefit under this Executive Severance Plan, the Company will interpret the Executive Severance Plan in such manner as it, in its sole and absolute discretion, deems necessary to comply with the requirements of Section 409A of the Code.”
2. The introductory sentence to the first question and answer of the Section entitled “Benefits Available Under this Executive Severance Plan”, is hereby amended in its entirety to read as follows:
“Subject to the Company’s timely receipt of an executed Agreement and Release, a Participant under this Executive Severance Plan will receive the following benefits:”
3. Paragraph 1 of the first question and answer of the Section entitled “Benefits Available Under this Executive Severance Plan”, is hereby amended in its entirety to read as follows:
| “1. | Severance Payment |
Participants in this Executive Severance Plan will receive a one-time lump sum cash severance payment in an amount equal to: (i) a multiple of the Participant’s annualized base salary, such multiple to be based on the Participant’s position with the Company immediately prior to the termination as set forth in the following chart plus (ii) the Participant’s target annual incentive award for the year of the termination, prorated for the portion of the year prior to such termination.
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Position | Multiple of Base Salary | |
Chief Executive Officer | 3x | |
Member of Senior Leadership Team | 2x | |
Member of Leadership Team | 1x | |
The severance payment will be made within the 90-day period following the Participant’s termination of employment; provided that if the 90-day period begins in one taxable year of the Participant and ends in a subsequent taxable year of the Participant, such payment shall be made in the subsequent taxable year. Notwithstanding the foregoing, if the Participant is a “specified employee” within the meaning of Code Section 409A, the severance payment will, to the extent required under Code Section 409A, be made on the first business day following the expiration of six months from the date of Participant’s termination of employment.
The severance payment will be subject to all applicable tax withholdings and will also be reduced by the amount of any obligations which the Participant owes to the Company. Such obligations may include, but are not limited to, some or all of the following:
| (1) | The entire balance, if any, owed under the Company’s appliance purchase plan, energy conservation program or employee relocation plan; and |
| (2) | Any amounts owed on Company issued or sponsored travel or credit cards or any other expenses or payments for which the Company should be reimbursed.” |
4. Paragraph 2 of the first question and answer of the Section entitled “Benefits Available Under this Executive Severance Plan”, is hereby amended in its entirety to read as follows:
| “2. | Health Care Benefits |
Participants who, under the terms and conditions of the applicable health care plans covering them immediately prior to their severance, are eligible for retiree health care coverage will be able to participate in, and receive, such retiree health care coverage subject to the terms and conditions of the relevant health care plan documents as they may be amended (or terminated) from time to time. Participants who are not eligible for, or who do not choose coverage under, the Company’s retiree health care coverage, will
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be eligible for continued health care coverage in accordance with applicable law. The required contribution by the Participant for such continued coverage for the period set forth in the following chart will be the applicable employee rate, unless and until the Participant becomes eligible for coverage for a particular type of benefit through employment with another employer, at which time the required contribution for continuing such benefit coverage hereunder shall be the applicable COBRA rate for such benefit. The period of continued health care coverage provided for herein shall run concurrently with the Participant’s available COBRA coverage period.
Position | Period of Subsidized Premium for Health Care Coverage | |
Chief Executive Officer | 18 months | |
Member of Senior Leadership Team | 18 months | |
Member of Leadership Team | 1 year | |
If a Participant who is the Chief Executive Officer or a member of the Senior Leadership Team is covered under the Company’s health care plans through the end of such eighteen (18) month period, then such Participant shall receive an additional payment, on the last day of such eighteen (18) month period, in an amount equal to the monthly cost of such coverage (determined as of such date) for the period provided in the following table:
Position | Period of Subsidized Premium for Health Care Coverage | |||
Chief Executive Officer | 18 months | |||
Member of Senior Leadership Team | 6 months | |||
Such payment shall be made in a lump sum.”
5. Paragraph 7 of the first question and answer of the Section entitled “Benefits Available Under this Executive Severance Plan”, is hereby added to read as follows:
“7.Administrative Delay in Payment. Benefits under this Executive Severance Plan shall be paid on the date specified hereunder; provided that, in the case of administrative necessity, the payment of such benefits may be delayed up to the last day
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of the calendar year in which payment would otherwise be made or, if later, the 15th day of the third calendar month following the date on which payment would otherwise be made.”
IN WITNESS WHEREOF, and as conclusive evidence of the adoption of the foregoing instrument comprising an Amendment to the Energy Future Holdings Corp. Executive Severance Plan, Energy Future Holdings Corp. has caused these presents to be duly executed in its name and on its behalf this 20th day of December, 2010.
| By: | /s/ RICHARD LANDY | |
| Richard Landy | ||
| Executive Vice President, Human Resources |
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Exhibit 10(i)
EFH EXECUTIVE ANNUAL INCENTIVE PLAN
Plan Document
Amended, effective as of January 1, 2010
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Contents
| Article I. | Purpose. | 1 | ||||
| Article II. | Definitions. | 1 | ||||
| Article III. | Eligibility and Participation. | 3 | ||||
| Article IV. | Establishment of Performance Goals. | 3 | ||||
| Article V. | Establishment of Awards. | 3 | ||||
| Article VI. | Application of Individual Performance Modifier and Determination of Individual Participant Awards. | 3 | ||||
| Article VII. | Payment of Awards. | 4 | ||||
| Article VIII. | Termination of Employment and Partial Awards. | 4 | ||||
| Article IX. | Administrative Provisions. | 5 |
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EFH EXECUTIVE ANNUAL INCENTIVE PLAN
Article I.Purpose.
The EFH Executive Annual Incentive Plan (the “Plan”) is amended effective as of January 1, 2010. The Plan, as herein amended, supersedes and replaces all other Plan documents. The Plan provides for annual bonus incentive award opportunities for eligible Participants payable in cash. This Plan, as herein amended, supersedes and replaces all other Plan documents.
The principal purposes of the Plan are to attract, motivate and retain key employees; to align the interests of Participants, Participating Employers and Company shareholders by rewarding performance that satisfies established performance goals; to motivate Participant behaviors that drive successful results at the corporate, business unit and individual levels; and to support collaboration across essential organizational interfaces.
Article II.Definitions.
When used in the Plan, the following terms shall have the meanings set forth below:
(a) “Additional Persons” means such other individuals who are not Executive Officers under the Plan, but who are senior officers and key employees identified by the O&C Committee, in consultation with the Company’s Chief Executive Officer.
(b) “Aggregate Incentive Pool” means the amount equal to the Target Incentive Pool multiplied by the Weighted Funding Percentage.
(c) “Award” means the amount payable to a Participant under this Plan for any Plan Year, as determined in accordance with the terms of the Plan.
(e) “Base Salary” means the annualized base salary designated for the Participant in the applicable payroll records of the Participating Employer, prior to any deferrals, and excluding any overtime pay, bonuses, incentive compensation, expense reimbursements and fringe benefits of any kind for the applicable Plan Year.
(f) “Business Unit” means, individually, or “Business Units” means, collectively, the “TXU Energy”, “Luminant” and “Corporate Services” business units of the Company, which are the participating Employers in this Plan.
(g) “Company” means Energy Future Holdings Corp., and its successors and assigns. With respect to a particular Participant, Company means such Participant’s employer.
(h) “Disability” or “Disabled” means disability as determined under the EFH Long-Term Disability Income Plan, or any successor plan covering Participants.
(i) “Executive Officers” means the Company’s Chief Executive Officer and other Executive Officers, as defined under the charter of the O&C Committee.
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(j) “Financial Performance Criteria” means various measures of financial performance of the Company established by the O&C Committee for the Plan Year.
(k) “Financial Performance Funding Percentage” means a percentage used to calculate the Aggregate Incentive Pool established by the O&C Committee based on the performance of the Company against the Financial Performance Criteria established for the particular Plan Year.
(l) “Individual Performance Modifier” means individual Participant performance approved by the SPC or O&C Committee (with respect to Executive Officers and Additional Persons) and used in determining a Participant’s Award.
(m) “O&C Committee” means the Organization and Compensation Committee of the Board of Directors of the Company.
(n) “Operational Metrics” means non-financial objectives established by each Business Unit that are critical to the function and success of the business.
(o) “Operational Metrics Funding Percentage” means a percentage used to calculate Aggregate Incentive Pool established by the O&C Committee based on the accomplishment of Operational Metrics for the particular Plan Year.
(p) “Participant” means an individual who is an officer of a Participating Employer having a title of vice president or above and who is employed by the Company for a period of three full months during the Plan Year.
(q) “Participating Employer” means, the Company and each of the Business Units. Additional Participating Employers may be added with the approval of the O&C Committee, and participation in the Plan by any such additional Participating Employers will commence as of the effective date designated by the O&C Committee.
(r) “Plan” means this EFH Executive Annual Incentive Plan.
(s) “Plan Year” means the twelve (12) month period beginning January 1 and ending December 31.
(t) “Retirement” means retirement from active employment with the Company upon attaining at least age 55 and completing at least 16 years of service with the Company and any of its subsidiaries.
(u) “SPC” means the group of executive officers of the Company referred to internally as the Strategy & Policy Committee.
(v) “Target Award” means an Award level of an individual Participant, expressed as a percentage of the Participant’s Base Salary,. The Target Award shall be used in calculating an individual’s actual Award for a Plan year.
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(w) “Target Incentive Pool” means the amount equal to the aggregate of the Target Awards for all Participants, or a selected group of Participants, as the context may require.
(x) “Weighted Funding Percentage” means the percentage that is the sum of the Financial Performance Funding Percentage and the Operational Metrics Funding Percentage.
Article III.Eligibility and Participation.
All individuals who, as of the first day of a Plan Year, meet the definition of a Participant hereunder, shall be eligible to participate in this Plan for such Plan Year. Awards, if any, for individuals who become Participants during the Plan Year or whose participation in this Plan is terminated during the Plan Year, shall be determined under, and in accordance with, Article VIII hereof. Participation in this Plan for any Plan Year shall not entitle an individual to future participation.
Article IV.Establishment of Performance Goals.
For each Plan Year, the O&C Committee establishes (i) the Financial Performance Criteria, (ii) the Operational Metrics, and (iii) the Target Incentive Pool. Such determinations by the O&C Committee shall be made at such times and shall be based on such criteria as the O&C Committee shall determine, respectively, in their sole discretion. The O&C Committee shall have full authority and discretion, for any particular Plan Year, to modify any of its determinations hereunder, with respect to all Participants or any individual Participant, including determinations which affect the calculation or amount of Awards, in order to take into consideration other benefit programs and/or extraordinary events affecting the financial results of the Company or a Business Unit. Once determined, or modified, such determinations shall be communicated to the affected Participants in such form and manner as the O&C Committee determines to be appropriate.
Article V.Establishment of Awards.
After the end of the Plan Year, the O&C Committee shall determine the Financial Performance Funding Percentage and the Operational Metrics Funding Percentage for each Plan Year. The O&C Committee shall further determine the Weighted Funding Percentage and the resulting Aggregate Incentive Pool for the Plan Year.
Article VI. Application of Individual Performance Modifier and Determination of Individual Participant Awards.
| A. | Individual Participant Awards. |
The SPC shall determine each Participant’s Award, other than for Executive Officers and Additional Persons, for a Plan Year by: (i) multiplying the Participant’s Target Award by the Weighted Funding Percentage; and (ii) multiplying such amount by the applicable Individual Performance Modifier determined in accordance with Article VI.B. below.
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| B. | Application of Individual Performance Modifier. |
As described in Article VI.A. above, the amount determined by applying the formula set forth in Article VI.A. shall be adjusted by applying the Individual Performance Modifier for each Participant. The SPC, in its sole discretion, shall determine a Participant’s Individual Performance Modifier, other than for Executive Officers and Additional Persons, based on the Participant’s performance, which may range from 0% to 150%.
In no event may the aggregate of all Awards determined to be payable to all Participants exceed the Aggregate Incentive Pool.
| C. | Determination of Awards for Executive Officers and Additional Persons. |
The O&C Committee shall determine the individual Participant Awards in accordance with Article VI.A. above, and the Individual Performance Modifier in accordance with Article VI.B. above, with respect to Executive Officers and Additional Persons who are Participants in the Plan.
Article VII.Payment of Awards.
All Awards will be paid in cash to Participants by March 15 of the year following the applicable Plan Year, subject to applicable tax withholding requirements.
Article VIII.Termination of Employment and Partial Awards.
Participation in the Plan shall cease immediately upon a Participant’s resignation or termination of employment for any reason (with or without cause), or upon the Participant’s death, Disability or Retirement. In such event, the Participant may be eligible for a partial award for such Plan Year in accordance with and subject to the provisions of this Article VIII.
| A. | Resignation or Termination. |
If a Participant resigns or his/her employment with a Participating Employer is terminated (with or without cause) prior to the submission of the Award to payroll for payment for reasons other than death, Disability, Retirement, or transfer to an affiliate of the Company, such Participant shall forfeit any right to receive such Award.
| B. | Death, Disability or Retirement. |
If a Participant dies, becomes Disabled or Retires during a Plan Year after having attained at least three (3) full months of participation in the Plan during such Plan Year, the Participant, or the Participant’s beneficiary in the case of the Participant’s death, may, in the sole discretion of the SPC or O&C Committee (with respect to Executive Officers and Additional Persons), be entitled to receive a partial Award, prorated for the number of months that the individual was a Participant hereunder during the Plan Year. For purposes of applying this proration, a month shall include each month during which the individual was employed by a Participating Employer through at least the 15th day of such month prior to the individual’s death, Disability or Retirement. Any such Award shall be paid at the time and in the form that
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all other Awards are paid for such Plan Year. The decisions of the SPC and O&C Committee with respect to such Awards shall be final and binding on all parties. For purposes of this provision, a Participant’s beneficiary shall be his/her surviving spouse or, if he/she has no surviving spouse, his/her estate.
| C. | Transfers. |
If a Participant (i) transfers from a Participating Employer to an affiliate of the Company after having attained at least three (3) full months of participation in the Plan during the Plan Year, and (ii) continues to be employed by an affiliate of the Company through the remainder of the Plan Year, such individual may, in the sole discretion of the SPC or O&C Committee (with respect to Executive Officers and Additional Persons), be entitled to receive a partial Award hereunder, prorated on the basis of the number of months such individual was employed by the Participating Employer during the Plan Year. For purposes of applying this proration, a Participant shall be deemed to have been employed by the Participating Employer for a month if such Participant was employed by the Participating Employer on the 15th day of such month. Any such Award shall be paid at the time and in the form that all other Awards are paid for such Plan Year. The decisions of the SPC and O&C Committee with respect to such Awards shall be final and binding on all parties.
| D. | Participant Status Attained During Plan Year. |
If an individual becomes a Participant during a Plan Year, the Participant, may, in the sole and absolute discretion of the SPC or O&C Committee (with respect to Executive Officers and Additional Persons), be eligible to receive a partial Award hereunder, prorated on the basis of the number of months such individual was a Participant during the Plan Year, provided that the Participant attained at least three (3) full months of participation in the Plan during the Plan Year. For purposes of applying this proration, a Participant shall be deemed to have been employed by the Participating Employer for a month if such Participant was employed by the Participating Employer on the 15th day of such month. Any such Award shall be paid at the time and in the form that all other Awards are paid for such Plan Year. The decisions of the SPC and O&C with respect to such Awards shall be final and binding on all parties.
Article IX.Administrative Provisions.
| A. | Administration. |
The Plan shall be administered and interpreted by the Participating Employers through the individuals who have been provided authority hereunder to carry out the administration of this Plan. The O&C Committee and its members, the SPC and its members, and any other individual to whom the O&C and/or SPC has delegated their responsibilities regarding the administration of this Plan, shall have full authority, discretion and power necessary or desirable to administer and interpret this Plan. Without in any way limiting the foregoing, all such individuals shall have complete authority, discretion and power to: (i) determine the Participants for each Plan Year; (ii) determine the Individual Performance Modifier applicable to each Participant; (iii) evaluate and determine the performance of Participants; (iv) determine the amount of the Award for each Participant; (v) interpret the provisions of this Plan and any other
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documentation used in connection with this Plan, including documentation specifying individual Performance Goals, Award opportunities and the like; (vi) establish and interpret rules and procedures (written or by practice) for the administration of the Plan; and (vii) make all other determinations and take all other actions necessary or desirable for the administration or interpretation of this Plan. All actions, decisions and interpretations of such individuals shall be final, conclusive and binding on all parties.
| B. | No Right to Continued Employment. |
Nothing in this Plan shall be deemed by implication, action or otherwise to constitute a contract of employment, or otherwise to provide a Participant with any right of continued employment or impose any limitation on any right of a Participating Employer to terminate a Participant’s employment at any time.
| C. | No Assignment. |
A Participant or Participant’s beneficiary shall have no right to anticipate, alienate, sell, transfer, assign, pledge or encumber any right to receive any incentive made under the Plan, nor will any Participant or Participant’s beneficiary have any lien on any assets of any Participating Employer, or any affiliate thereof, by reason of any Award made under the Plan.
| D. | Withholding. |
The Participating Employers shall have the right to deduct or withhold, or require a Participant to remit to the applicable Participating Employer, any taxes required by law to be withheld from Awards made under this Plan.
| E. | Amendment of Plan. |
The Plan may be amended, suspended or terminated at any time and from time to time, by action of the O&C Committee. In order to be effective, any amendment of this Plan or any Award must be in writing. No oral statement, representation or the like shall have the effect of amending or modifying this Plan or any Award, or otherwise have any binding effect on the Company, the O&C Committee, the SPC, or any individual who has been delegated authority by the O&C Committee or the SPC to administer this Plan.
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| F. | No Obligation to Continue Plan. |
The adoption of the Plan does not imply any commitment to continue to maintain the Plan, or any modified version of the Plan, or any other plan for incentive compensation for any succeeding year.
| G. | Governing Law. |
The Plan shall be construed in accordance with, and governed by, the laws of the State of Texas. Any disputes arising under this Plan and any action to enforce any provisions hereof, shall be maintained exclusively in the appropriate courts of Dallas County, Texas.
| H. | Severability. |
In case any provision of the Plan shall be held illegal or void, such illegality or invalidity shall not affect the remaining provisions of this Plan, but shall be fully severable, and the Plan shall be construed and enforced as if said illegal or invalid provisions had never been inserted herein.
| I. | Limitation of Liability. |
Except for their own gross negligence or willful misconduct regarding the performance of the duties specifically assigned to them under, or their willful breach of the terms of this Plan, the Participating Employer, the O&C Committee and its members, the SPC and its members, and any other entity or individual administering any aspect of this Plan shall be held harmless by the Participants and their respective representatives, heirs, successors, and assigns, against liability or losses occurring by reason of any act or omission under the Plan.
| J. | Section 409A Compliance |
To the extent applicable, the Plan is intended to comply with, or be exempt from, section 409A of the Internal Revenue Code of 1986 as amended (the “Code”), and shall be administered, construed, and interpreted in accordance with such intent. Payments under this Plan shall be made in a manner that will comply with, or be exempt from, section 409A of the Code, including regulations or other guidance issued with respect thereto, except as otherwise determined by the Company. The applicable provisions of section 409A of the Code are hereby incorporated by reference and shall control over any contrary provisions herein that conflict therewith.
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Executed August 3, 2010 to be effective as January 1, 2010.
| Energy Future Holdings Corp. | ||
| By: | /s/ RICHARD LANDY | |
| Rich Landy | ||
| Executive Vice President, Human Resources | ||
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Exhibit 10(l)
SECOND AMENDMENT TO EFH SECOND SUPPLEMENTAL RETIREMENT PLAN
Pursuant to the authority of the Board of Directors of Energy Future Holdings Corp., and the provisions of Section 5.1 thereof, the EFH Second Supplemental Retirement Plan (“Plan”), as amended and restated as of October 10, 2007, is hereby amended in the following respects only, effective as of January 1, 2010.
| (1) | Section 2.9 of the Plan is hereby amended in its entirety to read as follows: |
“2.9 “Participant” shall mean each person who is entitled to receive a benefit on or after January 1, 1983, under the Retirement Plan and whose Retirement Benefit is less than his Adjusted Retirement Benefit, but excluding any Participant who is eligible to receive benefits under (1) the Retirement Income Restoration Plan of ENSERCH Corporation and Participating Subsidiary Companies or (2) the Oncor Supplemental Retirement Plan, to the extent of any benefit attributable to service with Oncor Electric Delivery Company LLC.”
| (2) | Section 2.10 of the Plan is hereby amended in its entirety to read as follows: |
“2.10 “Participating Employer” shall mean the Company or any Affiliated Entity which has been approved for participation in, and which has adopted, the Plan. “Participating Employers” shall be used to refer to such entities jointly or severally. Effective as of January 1, 2010, Oncor Electric Delivery Company LLC shall no longer be a Participating Employer in this Plan.”
| (3) | Section 2.19 of the Plan is hereby amended by adding the following sentences to the end of existing Section 2.19: |
“Notwithstanding the foregoing, the Supplemental Retirement Benefit shall not include any amount attributable to service with Oncor Electric Delivery Company LLC, as determined by the actuary, which benefit shall be provided under the Oncor Supplemental Retirement Plan. In no event shall a Participant’s total Benefit under this Plan and the Oncor Supplemental Retirement Plan exceed the Benefit such Participant would be entitled to receive under this Plan, if such Participant’s service with Oncor Electric Delivery Company LLC were taken into account under this Plan.”
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IN WITNESS WHEREOF, and as conclusive evidence of the adoption of the foregoing instrument Amendment to the EFH Second Supplemental Retirement Plan, the Board of Directors of Energy Future Holdings Corp. has caused these presents to be duly executed in the name and on the behalf of Energy Future Holdings Corp., by an authorized officer thereof, thereunto duly authorized this 9th day of April, 2010.
| ENERGY FUTURE HOLDINGS CORP. |
/s/ PAUL KEGLEVIC |
| Paul Keglevic, |
| Executive Vice President & |
| Chief Financial Officer |
| REVIEWED & APPROVED |
|
| Richard Landy, |
| Executive Vice President, Human Resources |
|
| Russell Graves, |
| Director, Total Rewards |
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Exhibit 10(m)
THIRD AMENDMENT TO EFH SECOND SUPPLEMENTAL RETIREMENT PLAN
Pursuant to the authority of the Board of Directors of Energy Future Holdings Corp., and the provisions of Section 5.1 thereof, the EFH Second Supplemental Retirement Plan (“Plan”), as amended and restated as of October 10, 2007, is hereby amended in the following respects only, effective, except as otherwise stated, as of January 1, 2010.
| (1) | The Plan is hereby amended by adding a new subsection (c) to Section 4.2 to read as follows: |
“(c) Notwithstanding subsection (b), effective with respect to any Participant who experiences a Separation from Service on or after March 1, 2010, if the lump sum present value of a Participant’s entire vested Supplemental Retirement Benefit under the Plan is $5,000 or less upon his or her Separation from Service, the present value of such Participant’s Supplemental Retirement Benefit shall be paid to such Participant in a single lump sum upon such Participant’s Separation from Service.”
IN WITNESS WHEREOF, and as conclusive evidence of the adoption of the foregoing instrument Amendment to the EFH Second Supplemental Retirement Plan, the Board of Directors of Energy Future Holdings Corp. has caused these presents to be duly executed in the name and on the behalf of Energy Future Holdings Corp., by an authorized officer thereof, thereunto duly authorized this 21st day of April, 2010.
| ENERGY FUTURE HOLDINGS CORP. |
/s/ RICHARD LANDY |
| Richard Landy, |
| Executive Vice President, Human Resources |
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Exhibit 10(o)
Amendment to EFH Salary Deferral Program
Pursuant to Section 14 of the EFH Salary Deferral Program (“Plan”) and the authority delegated to the Non-Qualified Plan (“NQP”) Committee by the Board of Directors of Energy Future Holdings Corp. (the “Company”) to amend the Plan, the NQP Committee approves the following amendments to the Plan:
WHEREAS, the Company wishes to amend the Plan to provide for cashout of small accounts and to eliminate certain provisions applicable to amounts contributed to the Plan prior to April 1, 1998.
NOW, THEREFORE, the Plan is hereby amended as follows:
| 1. | The Plan is amended by adding a new sentence at the end of existing Section 6.1 to read as follows: |
Notwithstanding the foregoing, effective as of January 1, 2011, this Section 6.1 shall apply to the entirety of each Participant’s Account under the Plan, without regard to the date on which any amounts were deferred or contributed to the Plan.
| 2. | The Plan is amended by adding a new sentence at the end of existing Section 6.2 to read as follows: |
Notwithstanding the foregoing, effective as of January 1, 2011, the provisions of this Section 6.2 shall no longer apply and all Accounts under the Plan shall be invested in accordance with the provisions of Section 6.1.
| 3. | The Plan is amended by adding a new sentence at the end of existing Section 8.1(a) to read as follows: |
Notwithstanding the foregoing, effective as of January 1, 2011, this Section 8.1(a) shall apply to the entirety of each Participant’s Account under the Plan, without regard to the date on which any amounts were deferred or contributed to the Plan.
| 4. | The Plan is amended by adding a new sentence at the end of existing Section 8.1(b) to read as follows: |
Notwithstanding the foregoing, effective as of January 1, 2011, the provisions of this Section 8.1(b) shall no longer apply and all Accounts under the Plan shall be valued in accordance with the provisions of Section 8.1(a).
| 5. | The Plan is amended by adding a new Section 8.2(b)(vi) to read as follows: |
(vi) Notwithstanding the foregoing, with respect to any Participant who experiences a Separation from Service on or after January 1, 2011, if the aggregate balance of such
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Participant’s Accounts at such time is $5,000 or less, then the full value of such Participant’s Accounts shall be paid as a lump sum as soon as practicable, but in no event later than 60 days following such Separation from Service, subject to Section 8.3.
| 6. | The Plan is amended by adding a new Section 9.3 to read as follows: |
9.3Elimination of Special Provisions.
Notwithstanding the foregoing, from and after January 1, 2011, Exhibit B shall no longer apply.
| 7. | Except as amended hereby, the Plan shall remain in full force and effect. |
/s/ TONY HORTON January 13, 2011 | ||
| Tony Horton | Date | |
| Senior Vice President, Treasurer | ||
| Energy Future Holdings Corp. | ||
/s/ LINDA JOJO January 19, 2011 | ||
| Linda Jojo | Date | |
Senior Vice President, Chief Information Officer | ||
| Energy Future Holdings Corp. | ||
/s/ RICHARD LANDY January 20, 2011 | ||
| Rich Landy | Date | |
| Executive Vice President, Human Resources | ||
| Energy Future Holdings Corp. | ||
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Exhibit 10(dd)
Paul Keglevic
Employment Arrangement
In October 2009, the Organization and Compensation Committee (O&C Committee) of the Board approved several changes to Paul Keglevic’s compensation arrangement. Pursuant to Mr. Keglevic’s amended employment arrangement, effective January 1, 2010, Mr. Keglevic’s base salary was increased from $600,000 to $650,000, and Mr. Keglevic was granted a new cash-based retention incentive award (Retention Award). Under the terms of the Retention Award, Mr. Keglevic is entitled to receive on September 30, 2012, to the extent Mr. Keglevic remains employed by EFH Corp. on such date (with customary exceptions for death, disability and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 75% of the aggregate Executive Annual Incentive Plan award received by (or otherwise payable to) Mr. Keglevic for fiscal years 2009, 2010 and 2011. As described in greater detail in Item 9B of EFH Corp.’s annual report on Form 10-K for the fiscal year ended December 31, 2010, the O&C Committee recently approved a modification of the Retention Award.
Pursuant to Mr. Keglevic’s amended employment arrangement, Mr. Keglevic received a grant of 1,000,000 new stock options under the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and Affiliates (Stock Option Plan) at a strike price of $3.50 per share. Half of Mr. Keglevic’s new stock options are cliff-vested options that will vest 100% on September 30, 2014, and the other half are time-vested options that will vest 20% per year over a five-year period beginning September 30, 2009. In connection with the grant of these new stock options, Mr. Keglevic surrendered to EFH Corp. 500,000 unvested performance-related stock options that were granted to Mr. Keglevic when he joined EFH Corp. As described in greater detail in Item 9B of EFH Corp.’s annual report on Form 10-K for the fiscal year ended December 31, 2010, the O&C Committee recently approved an exchange program pursuant to which our executive officers, including Mr. Keglevic, may exchange any and all of their outstanding stock option awards.
Mr. Paul Keglevic forfeited his rights to the deferred shares granted to him in July 2008, and on July 28, 2010, the Organization and Compensation Committee of the Board of Directors of EFH Corp. approved certain changes to Mr. Keglevic’s compensation arrangement. Pursuant to the new arrangement, Mr. Keglevic will receive 225,000 shares of EFH Corp.’s common stock if he is employed by EFH Corp. on September 30, 2012. If Mr. Keglevic’s employment with EFH Corp. terminates for any reason prior to September 30, 2012 (other than for “cause” or without “good reason”), he will also be entitled to receive the 225,000 shares. If Mr. Keglevic receives the 225,000 shares in accordance with the terms of his new arrangement, he has the right to sell the shares to EFH Corp. for $3,140,000, at any time during the period beginning on September 30, 2012 and ending on the sixtieth business day following his termination of employment (or, in the event Mr. Keglevic receives the shares upon his termination of employment, at any time during the period ending on the sixtieth business day following his termination of employment).
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Exhibit 10(ee)
DEFERRED SHARE AGREEMENT
This Deferred Share Agreement, dated as of July 1, 2008 (this “Agreement”) by and among Energy Future Holdings Corp. (“EFH Corp.”) and Paul Keglevic (the “Executive”).
WHEREAS, the Executive is employed byEFH Corp., pursuant to an employment agreement dated July 1, 2008 (the “Employment Agreement”);
WHEREAS, in connection with Executive’s continued employment with EFH Corp., EFH Corp. has agreed to deliver 225,000 shares of common stock, no par value, of EFH Corp. (“Shares”) under the terms of this Agreement;
NOW, THEREFORE, in consideration of the foregoing and the respective representations, warranties, covenants and agreements set forth in this Agreement, and intending to be legally bound hereby, the parties hereto agree as follows:
ARTICLE I
DEFERRED SHARE AWARD
1.1Number of Shares. Subject to the vesting requirements under Section 1.2(a), EFH Corp. shall deliver 225,000 Shares to the Executive on the Distribution Date; provided, however, that if, after the date hereof and prior to the Distribution Date, there is a merger, spin-off, stock dividend, recapitalization, reorganization, stock split or other similar event that results in an adjustment to an outstanding Share, the number of Shares to be delivered on the Distribution Date pursuant to this Section 1.1 shall be adjusted by the Board of Directors of EFH Corp. (or a committee thereof) in a manner which is necessary to reflect the effect of such event on the Shares, consistent with the treatment of stockholders of EFH Corp.
1.2Distribution Date.
(a) Provided the Executive is employed on the third anniversary of the Effective Date (as defined by the Employment Agreement) of Executive’s Employment Agreement with EFH Corp., the Shares shall vest and become nonforfeitable as to (i) 112,500 of the Shares on the date that is the third anniversary date of this Agreement and (ii) provided Executive is employed on the fifth anniversary of the Effective Date of Executive’s Employment, the remaining 112,500 of the Shares shall vest and become nonforfeitable on the date that is the fifth anniversary date of this Agreement;providedthat any shares not yet vested shall become 100% vested and become nonforfeitable upon the first to occur of (x) immediately prior to a Change of Control (as defined in the 2007 Stock Incentive Plan for Key Employees of EFH Corp.) or (y) a termination of Executive’s employment by EFH Corp. without Cause, by Executive for Good Reason or due to Executive’s death or Disability (“Cause,” “Good Reason” and “Disability” are defined as provided in the Employment Agreement). The Shares shall be delivered to the Executive on the “Distribution Date”, which, subject to Section 3.3 below, shall be the earliest of the following dates:
(1) the occurrence of Executive’s separation of service for any reason, or, if necessary to meet the distribution requirement of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), the date that is six months and one day following such separation; and
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(2) the occurrence of a change in the ownership or effective control of EFH Corp., or in the ownership of a substantial portion of the assets of EFH Corp., occurring prior to Executive’s separation from service; and
(3) the 90th day following the fifth anniversary date of the Agreement.
in each case within the meaning of, and interpreted in a manner consistent with regulations under, Section 409A of the Code.
(b) In the event of the Executive’s death, any distribution to which the Executive would be entitled shall be made to the Executive’s estate or in accordance with the Executive’s will, the designated beneficiary.
1.3Dividends. If there is any dividend or distribution in respect of outstanding Shares, the Executive shall be entitled to receive a payment in respect of the Shares in the amount and form, and at the time, that such payment would have been made had the Executive actually held the underlying Shares, subject to applicable withholding taxes.
1.4Right to Diversify. If, prior to the Distribution Date, any of the Shares, had they been delivered to the Executive, would be released from the transfer restrictions contained in the Management Stockholders Agreement and could have been sold by the Executive without violation of applicable law or EFH Corp.’s trading policy, then upon and following the time of such release, the Executive shall have the right (a “Diversification Right”), exercisable by written notice to EFH Corp. and subject to reasonable administrative limitations, to convert his right to receive any or all of the Shares on the Distribution Date into a right to receive cash on the Distribution Date. In addition, the Executive shall have a Diversification Right with respect to any Shares that he would have been permitted to sell under the Sale Participation Agreement had he actually owned the Shares. In the event the Executive exercises a Diversification Right with respect to any Shares, the cash to be delivered to him on the Distribution Date shall equal the Fair Market Value (as defined in the Management Stockholders Agreement) of the Shares as to which the Diversification Right was exercised on the date of such exercise, as subsequently credited with investment returns based on notional investments as selected by the Executive from time to time following exercise of the Diversification Right from among those that EFH Corp. shall make available from among those notional investments under any nonqualified deferred compensation plan then maintained by EFH Corp. (or, if no such notional investments are made available, with compound annual interest equal to the prevailing prime rate plus 2 percentage points, but in no event shall it exceed EFH Corp.’s borrowing rate).
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ARTICLE II
ADDITIONAL AGREEMENTS
2.1Additional Agreements. Simultaneously with the execution of this Agreement, the parties shall execute a Management Stockholders Agreement and a Sale Participation Agreement each of which shall apply to the Shares subject to this Agreement.
2.2Special Put Right. If the Executive’s employment with EFH Corp. terminates for any reason prior to July 1, 2013, other than for Cause or without Good Reason (as defined in the Employment Agreement), he shall have the right (but not the obligation) to sell to EFH Corp. all (but not less than all) of the Shares delivered pursuant to Section 1.2 for a purchase price of $3,200,000 (the “Special Put Right”). In the event the Executive intends to exercise the Special Put Right, he shall send written notice, postmarked on or prior to the sixtieth day following termination of his employment, to EFH Corp. of his intention to sell the Shares in exchange for the applicable purchase price (“Put Option Notice”). The completion of the purchase shall take place at the principal office of EFH Corp. no later than the twentieth business day (such date to be determined by EFH Corp.) after the giving of the Put Option Notice. The applicable purchase price shall be paid by delivery to the Executive of a check payable to the order of the Executive against delivery of duly executed stock powers transferring the Shares.
ARTICLE III
TAX MATTERS
3.1Tax Withholding and Reporting. Upon any Distribution Date, EFH Corp. shall be entitled to withhold from any payment or distribution to the Executive an amount necessary to satisfy applicable withholding taxes that become due by reason of such payment or distribution. EFH Corp. acknowledges that for income tax purposes, the Executive will not include into income any amount payable on the Distribution Date until payment is actually made on the Distribution Date. EFH Corp. shall report and file all EFH Corp. tax returns and information reports (including Form W-2) consistent with such position.
3.2Delivery Before Liquidity. If, on the Distribution Date, (i) Shares are to be delivered to the Executive, and (ii) the Executive cannot resell promptly within a reasonable time thereafter such Shares either because there is no public market for the Shares, or the Executive is restricted under the Management Stockholders Agreement, EFH Corp. trading policies or applicable securities law from selling the Shares, EFH Corp. shall, immediately repurchase such number of Shares that, on the Distribution Date, have a Fair Market Value equal to the minimum statutory tax withholding obligation attributable to delivery of the Shares.
3.3Tax Assessment Prior to Distribution Date. If there is a final tax assessment against the Executive that any amount otherwise payable under this Agreement is taxable in a year prior to the year that includes the Distribution Date, EFH Corp. shall immediately pay or distribute the cash or Shares that otherwise would have been paid or delivered on the Distribution Date, and if the Executive cannot promptly within a reasonable time thereafter resell such Shares either because there is no public market for the Shares, or the Executive is restricted under the Management Stockholders Agreement, EFH Corp. trading policies or applicable securities law from selling the Shares, EFH Corp. shall immediately repurchase such number of Shares that, on the Distribution Date, have a Fair Market Value equal to the amount of such tax assessment (or, if such assessment exceeds the Fair Market Value of all of the Shares, then all of the Shares will be repurchased).
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ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF EFH CORP.
EFH Corp. hereby represents and warrants to the Executive as of the date hereof and the date of the Closing that:
4.1Corporate Existence and Power. EFH Corp. is a corporation duly formed, validly existing and in good standing under the laws of the State of Delaware.
4.2Authorization. The execution, delivery and performance by EFH Corp. of this Agreement and the consummation of the transactions contemplated hereby are within EFH Corp.’s corporate powers and have been duly authorized by all necessary action on the part of EFH Corp. This Agreement has been duly and validly executed and delivered by EFH Corp. Assuming this Agreement is the valid and binding agreement of each of the Executive, this Agreement constitutes the legal, valid and binding agreement of EFH Corp., enforceable against EFH Corp. in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, and other laws of general application affecting enforcement or creditors’ rights generally and general equitable principles.
4.3Noncontravention. The execution, delivery and performance by EFH Corp. of this Agreement does not and will not (a) violate the certificate of incorporation of EFH Corp., (b) violate any law, rule, regulation, judgment, injunction, order or decree applicable to or binding upon EFH Corp., (c) require any consent or other action by any person under, constitute a default under (with due notice or lapse of time or both), or give rise to any right of termination, cancellation or acceleration of any right or obligation of EFH Corp. or to a loss of any benefit to which EFH Corp. is entitled under any provisions of any agreement or other instrument binding upon EFH Corp. or any of its assets or properties or (d) result in the creation or imposition of any material mortgage, lien, pledge, charge, security interest or encumbrance on any property or asset of EFH Corp.
4.4Valid Issuance of Securities. The Shares which may be issued to the Executive hereunder will, when issued and delivered in accordance with the terms hereof, have been duly and validly authorized and issued and will be fully paid and nonassessable.
ARTICLE V
MISCELLANEOUS
5.1Notices. All notices and other communications required or permitted hereunder shall be in writing and shall be deemed effectively given: (a) upon personal delivery to the party to be notified, (b) when sent by confirmed facsimile if sent during normal business hours of the recipient, if not, then on the next business day, (c) five (5) days after having been sent by registered or certified mail, return receipt requested, postage prepaid or (d) one (1) business day after deposit with a nationally recognized overnight
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courier, specifying next day delivery, with written verification of receipt. All communications shall be sent to such party’s address as set forth below or at such other address or to such other person as the party shall have furnished to each other party in writing in accordance with this provision:
if to EFH Corp., to:
Energy Future Holdings Corp.
c/o Kohlberg Kravis Roberts & Co. L.P.
9 West 57th Street, Suite 4200
New York, New York 10019
Attention: Marc Lipschultz
Facsimile: (212) 750-0003
and
TPG Capital, L.P.
301 Commerce Street, Suite 3300
Forth Worth, Texas 76102
Attention: Clive Bode
Facsimile:(817) 871-4000
with copies to:
Simpson Thacher & Bartlett LLP
425 Lexington Avenue
New York, New York 10017
Attention: Andrew W. Smith
Facsimile: (212) 455-2502
if to the Executive, at the Executive’s address on file with EFH Corp.
5.2Amendments and Waivers. Any provision of this Agreement may be amended or waived if, but only if, such amendment or waiver is in writing and is signed, in the case of an amendment, by each party to this Agreement, or in the case of a waiver, by the party against whom the waiver is to be effective. No failure or delay by any party in exercising any right, power or privilege hereunder shall operate as a waiver thereof nor shall any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any other right, power or privilege. The rights and remedies herein provided shall be cumulative and not exclusive of any rights or remedies provided by law.
5.3Successors and Assigns. The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns,provided that no party may assign, delegate or otherwise transfer any of its rights or obligations under this Agreement without the consent of (a) EFH Corp., in the case of assignment, delegation or transfer of any rights or obligations hereunder by the Executive, and (b) the Executive, in the case of assignment, delegation or transfer of any rights or obligations hereunder by EFH Corp.
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5.4Governing Law. This Agreement shall be governed by and construed in accordance with the law of the State of Delaware, without giving effect to any otherwise governing principles of conflicts of law.
5.5Jurisdiction; Arbitration.
(a) In the event of any controversy among the parties hereto arising out of, or relating to, this Agreement which cannot be settled amicably by the parties, such controversy shall be finally, exclusively and conclusively settled by mandatory arbitration conducted expeditiously in accordance with the American Arbitration Association rules by a single independent arbitrator. Such arbitration process shall take place in Dallas, Texas. The decision of the arbitrator shall be final and binding upon all parties hereto and shall be rendered pursuant to a written decision, which contains a detailed recital of the arbitrator’s reasoning. Judgment upon the award rendered may be entered in any court having jurisdiction thereof.
(b) In the event of any arbitration or other disputes with regard to this Agreement or any other document or agreement referred to herein, each party to this Agreement shall pay its own legal fees and expenses, unless otherwise determined by the arbitrator. If the Executive substantially prevails on any of his substantive legal claims, then EFH Corp. shall reimburse all legal fees and arbitration fees incurred by the Executive to arbitrate the dispute.
5.6Waiver Of Jury Trial. EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY LEGAL PROCEEDING ARISING OUT OF OR RELATED TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.
5.7Counterparts; Third Party Beneficiaries. This Agreement may be signed in any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument. No provision of this Agreement shall confer upon any person other than the parties hereto any rights or remedies hereunder.
5.8Entire Agreement. This Agreement constitutes the entire agreement between the parties with respect to the subject matter of this Agreement and supersedes all prior agreements and understandings, both oral and written, between the parties with respect to the subject matter of this Agreement.
5.9Captions. The captions herein are included for convenience of reference only and shall be ignored in the construction or interpretation hereof.
5.10Severability. If one or more provisions of this Agreement are held to be unenforceable under applicable law, such provision shall be deemed to be excluded from this Agreement and the balance of this Agreement shall be interpreted as if such provision were so excluded and shall be enforced in accordance with its terms to the maximum extent permitted by law.
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IN WITNESS WHEREOF, each of the undersigned has executed this Agreement as of the date first above written.
| ENERGY FUTURE HOLDINGS CORP. | ||
| By: | /s/ RIZWAN CHAND | |
| Name: Rizwan Chand | ||
| Title: Executive Vice President | ||
/s/ PAUL KEGLEVIC | ||
| Paul Keglevic | ||
[Signature Page to Deferred Share Agreement]
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Exhibit 10(hh)
DEFERRED SHARE AGREEMENT
This Deferred Share Agreement, dated as of May 20, 2008 (this “Agreement”) by and among Energy Future Holdings Corp. (“Parent”) and David A. Campbell (the “Executive”).
WHEREAS, the Executive is employed by Parent and Luminant Holding Company LLC (“Luminant”), a subsidiary of Parent, pursuant to an employment agreement dated May 9, 2008 (the “Employment Agreement”);
WHEREAS, in connection with Executive’s continued employment with Parent and Luminant, Parent has agreed to deliver 500,000 shares of common stock, no par value, of Parent (“Shares”) on the Distribution Date, as defined below;
NOW, THEREFORE, in consideration of the foregoing and the respective representations, warranties, covenants and agreements set forth in this Agreement, and intending to be legally bound hereby, the parties hereto agree as follows:
ARTICLE I
DEFERRED SHARE AWARD
1.1Number of Shares. Parent shall deliver 500,000 Shares to the Executive on the Distribution Date; provided, however, that if, after the date hereof and prior to the Distribution Date, there is a merger, spin-off, stock dividend, recapitalization, reorganization, stock split or other similar event that results in an adjustment to an outstanding Share, the number of Shares to be delivered on the Distribution Date pursuant to Section 1.1 shall be adjusted by the Board of Directors of Parent (or a committee thereof) in a manner which is necessary to reflect the effect of such event on the Shares, consistent with the treatment of stockholders of Parent.
1.2Distribution Date.
(a) The Shares shall be delivered to the Executive on the “Distribution Date”, which, subject to Section 3.3 below, shall be the earlier of the following dates:
(1) the occurrence of Executive’s separation of service for any reason, or, if necessary to meet the distribution requirement of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), the date that is six months and one day following such separation; and
(2) the later of January 2, 2009 or the occurrence of a change in the ownership or effective control of Parent, or in the ownership of a substantial portion of the assets of Parent;
in each case within the meaning of, and interpreted in a manner consistent with regulations under, Section 409A of the Code.
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(b) In the event of the Executive’s death, any distribution to which the Executive would be entitled shall be made to the Executive’s estate or in accordance with the Executive’s will, the designated beneficiary.
1.3Dividends. If there is any dividend or distribution in respect of outstanding Shares, the Executive shall be entitled to receive a payment in respect of the Shares in the amount and form, and at the time, that such payment would have been made had the Executive actually held the underlying Shares, subject to applicable withholding taxes.
1.4Right to Diversify. If, prior to the Distribution Date, any of the Shares, had they been delivered to the Executive, would be released from the transfer restrictions contained in the Management Stockholders Agreement and could have been sold by the Executive without violation of applicable law or Parent’s trading policy, then upon and following the time of such release, the Executive shall have the right (a “Diversification Right”), exercisable by written notice to Parent and subject to reasonable administrative limitations, to convert his right to receive any or all of the Shares on the Distribution Date into a right to receive cash on the Distribution Date. In addition, the Executive shall have a Diversification Right with respect to any Shares that he would have been permitted to sell under the Sale Participation Agreement had he actually owned the Shares. In the event the Executive exercises a Diversification Right with respect to any Shares, the cash to be delivered to him on the Distribution Date shall equal the Fair Market Value (as defined in the Management Stockholders Agreement) of the Shares as to which the Diversification Right was exercised on the date of such exercise, as subsequently credited with investment returns based on notional investments as selected by the Executive from time to time following exercise of the Diversification Right from among those that Parent shall make available from among those notional investments under any nonqualified deferred compensation plan then maintained by Parent (or, if no such notional investments are made available, with compound annual interest equal to the prevailing prime rate plus 2 percentage points, but in no event shall it exceed Parent’s borrowing rate).
ARTICLE II
ADDITIONAL AGREEMENTS
2.1Additional Agreements. Simultaneously with the execution of this Agreement, the parties shall execute a Management Stockholders Agreement and a Sale Participation Agreement each of which shall apply to the Shares subject to this Agreement
2.2Special Put Right. If the Executive’s employment with Parent and Luminant terminates for any reason prior to January 31, 2009, other than for Cause (as defined in the Employment Agreement), he shall have the right (but not the obligation) to sell to Parent all (but not less than all) of the Shares delivered pursuant to Section 1.2 for a purchase price of $2,500,000 (the “Special Put Right”). In the event the Executive intends to exercise the Special Put Right, he shall send written notice, postmarked on or prior to the sixtieth day following termination of his employment, to Parent of his intention to sell the Shares in exchange for the applicable purchase price (“Put Option Notice”). The completion of the purchase shall take place at the principal office of Parent no later than the twentieth business day (such date to be determined by Parent) after the giving of the Put Option Notice. The applicable purchase price shall be paid by delivery to the Executive of a check payable to the order of the Executive against delivery of duly executed stock powers transferring the Shares.
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ARTICLE III
TAX MATTERS
3.1Tax Withholding and Reporting. Upon any Distribution Date, Parent shall be entitled to withhold from any payment or distribution to the Executive an amount necessary to satisfy applicable withholding taxes that become due by reason of such payment or distribution. Parent acknowledges that for income tax purposes, the Executive will not include into income any amount payable on the Distribution Date until payment is actually made on the Distribution Date. Parent shall report and file all Parent tax returns and information reports (including Form W-2) consistent with such position.
3.2Delivery Before Liquidity. If, on the Distribution Date, (i) Shares are to be delivered to the Executive, and (ii) the Executive cannot resell promptly within a reasonable time thereafter such Shares either because there is no public market for the Shares, or the Executive is restricted under the Management Stockholders Agreement, Parent trading policies or applicable securities law from selling the Shares, Parent shall, immediately repurchase such number of Shares that, on the Distribution Date, have a Fair Market Value equal to the minimum statutory tax withholding obligation attributable to delivery of the Shares.
3.3Tax Assessment Prior to Distribution Date. If there is a final tax assessment against the Executive that any amount otherwise payable under this Agreement is taxable in a year prior to the year that includes the Distribution Date, Parent shall immediately pay or distribute the cash or Shares that otherwise would have been paid or delivered on the Distribution Date, and if the Executive cannot promptly within a reasonable time thereafter resell such Shares either because there is no public market for the Shares, or the Executive is restricted under the Management Stockholders Agreement, Parent trading policies or applicable securities law from selling the Shares, Parent shall immediately repurchase such number of Shares that, on the Distribution Date, have a Fair Market Value equal to the amount of such tax assessment (or, if such assessment exceeds the Fair Market Value of all of the Shares, then all of the Shares will be repurchased).
ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF PARENT
Parent hereby represents and warrants to the Executive as of the date hereof and the date of the Closing that:
4.1Corporate Existence and Power. Parent is a corporation duly formed, validly existing and in good standing under the laws of the State of Delaware.
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4.2Authorization. The execution, delivery and performance by Parent of this Agreement and the consummation of the transactions contemplated hereby are within Parent’s corporate powers and have been duly authorized by all necessary action on the part of Parent. This Agreement has been duly and validly executed and delivered by Parent. Assuming this Agreement is the valid and binding agreement of each of the Executive, this Agreement constitutes the legal, valid and binding agreement of Parent, enforceable against Parent in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, and other laws of general application affecting enforcement or creditors’ rights generally and general equitable principles.
4.3Noncontravention. The execution, delivery and performance by Parent of this Agreement does not and will not (a) violate the certificate of incorporation of Parent, (b) violate any law, rule, regulation, judgment, injunction, order or decree applicable to or binding upon Parent, (c) require any consent or other action by any person under, constitute a default under (with due notice or lapse of time or both), or give rise to any right of termination, cancellation or acceleration of any right or obligation of Parent or to a loss of any benefit to which Parent is entitled under any provisions of any agreement or other instrument binding upon Parent or any of its assets or properties or (d) result in the creation or imposition of any material mortgage, lien, pledge, charge, security interest or encumbrance on any property or asset of Parent.
4.4Valid Issuance of Securities. The Shares which may be issued to the Executive hereunder will, when issued and delivered in accordance with the terms hereof, have been duly and validly authorized and issued and will be fully paid and nonassessable.
ARTICLE V
MISCELLANEOUS
5.1Notices. All notices and other communications required or permitted hereunder shall be in writing and shall be deemed effectively given: (a) upon personal delivery to the party to be notified, (b) when sent by confirmed facsimile if sent during normal business hours of the recipient, if not, then on the next business day, (c) five (5) days after having been sent by registered or certified mail, return receipt requested, postage prepaid or (d) one (1) business day after deposit with a nationally recognized overnight courier, specifying next day delivery, with written verification of receipt. All communications shall be sent to such party’s address as set forth below or at such other address or to such other person as the party shall have furnished to each other party in writing in accordance with this provision:
if to Parent, to:
Energy Future Holdings Corp.
c/o Kohlberg Kravis Roberts & Co. L.P.
9 West 57th Street, Suite 4200
New York, New York 10020
Attention: Marc Lipschultz
Facsimile: (212) 750-0003
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and
TPG Capital, L.P.
301 Commerce Street, Suite 3300
Forth Worth, Texas 76102
Attention: Clive Bode
Facsimile: (817) 871-4000
with copies to:
Simpson Thacher & Bartlett LLP
425 Lexington Avenue
New York, New York 10017
Attention: Andrew W. Smith
Facsimile: (212) 455-2502
if to the Executive, at the Executive’s address on file with Parent.
5.2Amendments and Waivers. Any provision of this Agreement may be amended or waived if, but only if, such amendment or waiver is in writing and is signed, in the case of an amendment, by each party to this Agreement, or in the case of a waiver, by the party against whom the waiver is to be effective. No failure or delay by any party in exercising any right, power or privilege hereunder shall operate as a waiver thereof nor shall any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any other right, power or privilege. The rights and remedies herein provided shall be cumulative and not exclusive of any rights or remedies provided by law.
5.3Successors and Assigns. The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns,provided that no party may assign, delegate or otherwise transfer any of its rights or obligations under this Agreement without the consent of (a) Parent, in the case of assignment, delegation or transfer of any rights or obligations hereunder by the Executive, and (b) the Executive, in the case of assignment, delegation or transfer of any rights or obligations hereunder by Parent.
5.4Governing Law. This Agreement shall be governed by and construed in accordance with the law of the State of Delaware, without giving effect to any otherwise governing principles of conflicts of law.
5.5Jurisdiction; Arbitration.
(a) In the event of any controversy among the parties hereto arising out of, or relating to, this Agreement which cannot be settled amicably by the parties, such controversy shall be finally, exclusively and conclusively settled by mandatory arbitration conducted expeditiously in accordance with the American Arbitration Association rules by a single independent arbitrator. Such arbitration process shall take place in Dallas, Texas. The decision of the arbitrator shall be final and binding upon all parties hereto and shall be rendered pursuant to a written decision, which contains a detailed recital of the arbitrator’s reasoning. Judgment upon the award rendered may be entered in any court having jurisdiction thereof.
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(b) In the event of any arbitration or other disputes with regard to this Agreement or any other document or agreement referred to herein, each party to this Agreement shall pay its own legal fees and expenses, unless otherwise determined by the arbitrator. If the Executive substantially prevails on any of his substantive legal claims, then Parent shall reimburse all legal fees and arbitration fees incurred by the Executive to arbitrate the dispute.
5.6Waiver Of Jury Trial. EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY LEGAL PROCEEDING ARISING OUT OF OR RELATED TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.
5.7Counterparts; Third Party Beneficiaries. This Agreement may be signed in any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument. No provision of this Agreement shall confer upon any person other than the parties hereto any rights or remedies hereunder.
5.8Entire Agreement. This Agreement constitutes the entire agreement between the parties with respect to the subject matter of this Agreement and supersedes all prior agreements and understandings, both oral and written, between the parties with respect to the subject matter of this Agreement.
5.9Captions. The captions herein are included for convenience of reference only and shall be ignored in the construction or interpretation hereof.
5.10Severability. If one or more provisions of this Agreement are held to be unenforceable under applicable law, such provision shall be deemed to be excluded from this Agreement and the balance of this Agreement shall be interpreted as if such provision were so excluded and shall be enforced in accordance with its terms to the maximum extent permitted by law.
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IN WITNESS WHEREOF, each of the undersigned has executed this Agreement as of the date first above written.
| ENERGY FUTURE HOLDINGS CORP. | ||
| By: | /s/ RIZWAN CHAND | |
| Name: Rizwan Chand | ||
| Title: Executive Vice President | ||
/s/ DAVID CAMPBELL | ||
| David Campbell | ||
[Signature Page to Deferred Share Agreement]
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Exhibit 12 (a)
ENERGY FUTURE HOLDINGS CORP.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
| Successor | Predecessor | |||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | Period from October 11, 2007 Through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | 2006 | |||||||||||||||||||||||
EARNINGS: | ||||||||||||||||||||||||||||
Income (loss) from continuing operations | $ | (2,812 | ) | $ | 408 | $ | (9,998 | ) | $ | (1,361 | ) | $ | 699 | $ | 2,465 | |||||||||||||
Subtract: Equity in earnings of unconsolidated subsidiaries (net of tax) | (277 | ) | — | — | — | — | — | |||||||||||||||||||||
Add: Total federal income tax expense (benefit) | 389 | 367 | (471 | ) | (673 | ) | 309 | 1,263 | ||||||||||||||||||||
Fixed charges (see detail below) | 3,646 | 3,225 | 5,280 | 905 | 777 | 907 | ||||||||||||||||||||||
Distributed income of equity investees | 169 | — | — | — | — | — | ||||||||||||||||||||||
Total earnings (loss) | $ | 1,115 | $ | 4,000 | $ | (5,189 | ) | $ | (1,129 | ) | $ | 1,785 | $ | 4,635 | ||||||||||||||
FIXED CHARGES: | ||||||||||||||||||||||||||||
Interest expense | $ | 3,614 | $ | 3,190 | $ | 5,246 | $ | 899 | $ | 750 | $ | 877 | ||||||||||||||||
Rentals representative of the interest factor | 32 | 35 | 34 | 6 | 27 | 30 | ||||||||||||||||||||||
Total fixed charges | $ | 3,646 | $ | 3,225 | $ | 5,280 | $ | 905 | $ | 777 | $ | 907 | ||||||||||||||||
RATIO OF EARNINGS TO FIXED CHARGES (a) | — | 1.24 | — | — | 2.30 | 5.11 | ||||||||||||||||||||||
| (a) | Fixed charges exceeded earnings by $2.531 billion, $10.469 billion and $2.034 billion for the years ended December 31, 2010 and 2008 and for the period from October 11, 2007 through December 31, 2007, respectively. |
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EXHIBIT 21
ENERGY FUTURE HOLDINGS CORP.
SUBSIDIARY HIERARCHY
Effective December 31, 2010
Jurisdiction | ||
Energy Future Holdings Corp. | Texas | |
Energy Future Competitive Holdings Company | Texas | |
Texas Competitive Electric Holdings LLC | Delaware | |
TCEH Finance, Inc. | Delaware | |
Generation MT Company LLC | Delaware | |
Luminant Holding Company LLC | Delaware | |
Luminant Energy Company LLC | Texas | |
Luminant ET Services Company | Texas | |
Luminant Energy Trading California Company | Texas | |
Luminant Energy Services Company | Texas | |
Luminant Generation Company LLC | Texas | |
Nuclear Energy Future Holdings LLC | Delaware | |
Nuclear Energy Future Holdings II LLC | Delaware | |
Comanche Peak Nuclear Power Company LLC1 | Delaware | |
Valley NG Power Company LLC | Texas | |
Luminant Renewables Company LLC | Texas | |
| Texas | ||
Generation SVC Company | Texas | |
Luminant Power Services Company | Delaware | |
Big Brown 3 Power Company LLC | Texas | |
Big Brown Power Company LLC | Texas | |
Collin Power Company LLC | Delaware | |
DeCordova Power Company LLC | Texas | |
Lake Creek 3 Power Company LLC | Texas | |
Martin Lake 4 Power Company LLC | Texas | |
Monticello 4 Power Company LLC | Texas | |
Morgan Creek 7 Power Company LLC | Texas | |
Oak Grove Management Company LLC | Delaware | |
Oak Grove Power Company LLC | Texas | |
Sandow Power Company LLC | Texas | |
Tradinghouse 3 & 4 Power Company LLC | Texas | |
Tradinghouse Power Company LLC | Texas | |
Valley Power Company LLC | Texas | |
Luminant Mining Services Company | Delaware | |
Big Brown Lignite Company LLC | Texas | |
Luminant Big Brown Mining Company LLC | Texas | |
Luminant Mining Company LLC | Texas | |
Oak Grove Mining Company LLC | Texas | |
Luminant Mineral Development Company LLC | Texas | |
NCA Resources Development Company LLC | Texas | |
TXU Energy Retail Company LLC | Texas | |
TXU Retail Services Company | Delaware | |
TXU SESCO Company LLC | Texas | |
TXU SESCO Energy Services Company | Texas | |
TXU Energy Solutions Company LLC | Texas | |
TXU SEM Company | Delaware | |
Brighten Holdings LLC | Delaware | |
Brighten Energy LLC | Delaware | |
Energy Future Intermediate Holding Company LLC | Delaware | |
EFIH Finance Inc. | Delaware | |
Oncor Electric Delivery Holdings Company LLC | Delaware | |
Oncor Electric Delivery Company LLC2 | Delaware | |
Oncor Management Investment LLC3 | Delaware |
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Jurisdiction | ||
Oncor Electric Delivery Transition Bond Company LLC | Delaware | |
Oncor Electric Delivery Administration Corp. | Texas | |
Oncor License Holdings Company LLC | Texas | |
Oncor Communications Holdings Company LLC | Delaware | |
EFH Renewables Company LLC | Delaware | |
EFH Corporate Services Company | Texas | |
EFH CG Management Company LLC | Texas | |
Generation Development Company LLC | Delaware | |
NCA Development Company LLC | Texas | |
EFH Properties Company | Texas | |
Basic Resources Inc. | Texas | |
TXU Receivables Company | Delaware | |
EFH Vermont Insurance Company | Vermont | |
LSGT Gas Company LLC | Texas | |
LSGT SACROC, Inc. | Texas | |
Humphreys & Glasgow Limited | United Kingdom | |
EEC Holdings, Inc | Nevada | |
EECI, Inc. | Nevada | |
Ebasco Services of Canada, Ltd | Canada | |
| United Kingdom |
| 1 | 88% ownership interest |
| 2 | 80.033% ownership interest |
| 3 | Oncor Management Investment LLC owns 0.217% of Oncor Electric Delivery Company LLC. Regarding the ownership of Oncor Management Investment LLC, Oncor Electric Delivery Company LLC owns 100% of the Class A membership interests. Certain management employees of Oncor Electric Delivery Company LLC own 100% of the Class B membership interests. |
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Exhibit 23(a)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-165860 on Form S-3 of our reports dated February 17, 2011, relating to the consolidated financial statements of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) (which report expresses an unqualified opinion and includes an explanatory paragraph regarding EFH Corp.’s adoption of amended consolidation accounting standards related to variable interest entities and EFH Corp.’s adoption of amended guidance regarding transfers of financial assets effective January 1, 2010, on a prospective basis) and the effectiveness of EFH Corp.’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of EFH Corp. for the year ended December 31, 2010.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 17, 2011
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Exhibit 23(b)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in the Energy Future Holdings Corp. Registration Statement No. 333-165860 on Form S-3 of our report dated February 17, 2011, relating to the financial statements of Oncor Electric Delivery Holdings Company LLC and subsidiaries, appearing in the Annual Report on Form 10-K of Energy Future Holdings Corp. for the year ended December 31, 2010.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 17, 2011
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Exhibit 31(a)
ENERGY FUTURE HOLDINGS CORP.
Certificate Pursuant to Section 302
of Sarbanes – Oxley Act of 2002
I, John F. Young, certify that:
| 1. | I have reviewed this annual report on Form 10-K of Energy Future Holdings Corp.; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
| 4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| c. | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
| Date: February 17, 2011 | /s/ JOHN F. YOUNG | |||
| Signature: | John F. Young | |||
| Title: | President and Chief Executive Officer |
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Exhibit 31(b)
ENERGY FUTURE HOLDINGS CORP.
Certificate Pursuant to Section 302
of Sarbanes – Oxley Act of 2002
I, Paul M. Keglevic, certify that:
| 1. | I have reviewed this annual report on Form 10-K of Energy Future Holdings Corp.; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
| 4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| c. | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: February 17, 2011 | /s/ PAUL M. KEGLEVIC | |||
| Signature: | Paul M. Keglevic | |||
| Title: | Executive Vice President and Chief Financial Officer |
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Exhibit 32(a)
ENERGY FUTURE HOLDINGS CORP.
Certificate Pursuant to Section 906
of Sarbanes – Oxley Act of 2002
CERTIFICATION OF CEO
The undersigned, John F. Young, President and Chief Executive Officer of Energy Future Holdings Corp. (the “Company”), DOES HEREBY CERTIFY that:
| 1. | The Company’s Annual Report on Form 10-K for the period ended December 31, 2010 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
| 2. | Information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company. |
IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 17th day of February 2011.
/s/ JOHN F. YOUNG | ||
| Name: | John F. Young | |
| Title: | President and Chief Executive Officer |
A signed original of this written statement required by Section 906 has been provided to Energy Future Holdings Corp. and will be retained by Energy Future Holdings Corp. and furnished to the Securities and Exchange Commission or its staff upon request.
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Exhibit 32(b)
ENERGY FUTURE HOLDINGS CORP.
Certificate Pursuant to Section 906
of Sarbanes – Oxley Act of 2002
CERTIFICATION OF CFO
The undersigned, Paul M. Keglevic, Executive Vice President and Chief Financial Officer of Energy Future Holdings Corp. (the “Company”), DOES HEREBY CERTIFY that:
| 1. | The Company’s Annual Report on Form 10-K for the period ended December 31, 2010 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
| 2. | Information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company. |
IN WITNESS WHEREOF, the undersigned has caused this instrument to be executed this 17th day of February 2011.
/s/ PAUL M. KEGLEVIC | ||
| Name: | Paul M. Keglevic | |
| Title: | Executive Vice President and Chief Financial Officer |
A signed original of this written statement required by Section 906 has been provided to Energy Future Holdings Corp. and will be retained by Energy Future Holdings Corp. and furnished to the Securities and Exchange Commission or its staff upon request.
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Exhibit 99(b)
Energy Future Holdings Corp. Consolidated
Adjusted EBITDA Reconciliation
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
| (millions of dollars) | ||||||||
Net income (loss) attributable to EFH Corp. | $ | (2,812 | ) | $ | 344 | |||
Income tax expense | 389 | 367 | ||||||
Interest expense and related charges | 3,554 | 2,912 | ||||||
Depreciation and amortization | 1,407 | 1,754 | ||||||
EBITDA | $ | 2,538 | $ | 5,377 | ||||
Oncor EBITDA | — | (1,354 | ) | |||||
Oncor Holdings distributions | 169 | 216 | ||||||
Interest income | (10 | ) | (45 | ) | ||||
Amortization of nuclear fuel | 140 | 101 | ||||||
Purchase accounting adjustments (a) | 210 | 340 | ||||||
Impairment of goodwill | 4,100 | 90 | ||||||
Impairment of assets and inventory write down (b) | 15 | 42 | ||||||
Net gain on debt exchange offers | (1,814 | ) | (87 | ) | ||||
Net income attributable to noncontrolling interests | — | 64 | ||||||
Equity in earnings of unconsolidated subsidiary | (277 | ) | — | |||||
EBITDA amount attributable to consolidated unrestricted subsidiaries | 1 | 3 | ||||||
Unrealized net gain resulting from hedging transactions | (1,221 | ) | (1,225 | ) | ||||
Amortization of “day one” net loss on Sandow 5 power purchase agreement | (22 | ) | (10 | ) | ||||
Losses on sale of receivables | — | 12 | ||||||
Noncash compensation expenses (c) | 18 | 11 | ||||||
Severance expense (d) | 4 | 10 | ||||||
Transition and business optimization costs (e) | 4 | 22 | ||||||
Transaction and merger expenses (f) | 48 | 81 | ||||||
Restructuring and other (g) | (117 | ) | (14 | ) | ||||
Expenses incurred to upgrade or expand a generation station (h) | 100 | 100 | ||||||
Adjusted EBITDA per Incurrence Covenant | $ | 3,886 | $ | 3,734 | ||||
Add Oncor Adjusted EBITDA (reduced by Oncor distributions/ dividends) | $ | 1,354 | $ | 1,123 | ||||
Adjusted EBITDA per Restricted Payments Covenant | $ | 5,240 | $ | 4,857 | ||||
| (a) | Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits not recognized in net income due to purchase accounting. |
| (b) | Impairment of assets includes impairments of land and charges related to the cancelled development of coal-fueled generation facilities. |
| (c) | Noncash compensation expenses are accounted for under accounting standards related to stock compensation and exclude capitalized amounts. |
| (d) | Severance expense includes amounts incurred related to outsourcing, restructuring and other amounts deemed to be in excess of normal recurring amounts. |
| (e) | Transition and business optimization costs include professional fees primarily for retail billing and customer care systems enhancements and incentive compensation. |
| (f) | Transaction and merger expenses include costs related to the Merger and abandoned strategic transactions, outsourcing transition costs, administrative costs related to the cancelled program to develop coal-fueled generation facilities, the Sponsor Group management fee and costs related to certain growth initiatives. |
| (g) | Restructuring and other for 2010 includes a gain on termination of a long-term power sales contract and for 2009 primarily represents reversal of certain liabilities accrued in purchase accounting and recorded as other income, partially offset by restructuring and nonrecurring activities. |
| (h) | Expenses incurred to upgrade or expand a generation station reflect noncapital outage costs. |
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Exhibit 99(c)
Texas Competitive Electric Holdings Company LLC Consolidated
Adjusted EBITDA Reconciliation
| Year Ended December 31 | ||||||||
| 2010 | 2009 | |||||||
| (millions of dollars) | ||||||||
Net income (loss) | $ | (3,383 | ) | $ | 709 | |||
Income tax expense | 402 | 447 | ||||||
Interest expense and related charges | 2,837 | 1,833 | ||||||
Depreciation and amortization | 1,380 | 1,172 | ||||||
EBITDA | $ | 1,236 | $ | 4,161 | ||||
Interest income | (91 | ) | (64 | ) | ||||
Amortization of nuclear fuel | 140 | 101 | ||||||
Purchase accounting adjustments (a) | 163 | 293 | ||||||
Impairment of goodwill | 4,100 | 70 | ||||||
Impairment of assets and inventory write down (b) | 13 | 36 | ||||||
Net gain on debt exchange offers | (687 | ) | — | |||||
EBITDA amount attributable to consolidated unrestricted subsidiaries | 1 | 3 | ||||||
Unrealized net gain resulting from hedging transactions | (1,221 | ) | (1,225 | ) | ||||
Amortization of “day one” net loss on Sandow 5 power purchase agreement | (22 | ) | (10 | ) | ||||
Corporate depreciation, interest and income tax expenses included in SG&A expense | 9 | 6 | ||||||
Losses on sale of receivables | — | 12 | ||||||
Noncash compensation expense (c) | 14 | 1 | ||||||
Severance expense (d) | 3 | 10 | ||||||
Transition and business optimization costs (e) | 9 | 25 | ||||||
Transaction and merger expenses (f) | 38 | 5 | ||||||
Restructuring and other (g) | (116 | ) | (19 | ) | ||||
Expenses incurred to upgrade or expand a generation station (h) | 100 | 100 | ||||||
Adjusted EBITDA per Incurrence Covenant | $ | 3,689 | $ | 3,505 | ||||
Expenses related to unplanned generation station outages | 132 | 91 | ||||||
Other adjustments allowed to determine Adjusted EBITDA per Maintenance Covenant (i) | 29 | 38 | ||||||
Adjusted EBITDA per Maintenance Covenant | $ | 3,850 | $ | 3,634 | ||||
| (a) | Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits not recognized in net income due to purchase accounting. |
| (b) | Impairment of assets includes impairment of land. |
| (c) | Noncash compensation expenses are accounted for under accounting standards related to stock compensation and exclude capitalized amounts. |
| (d) | Severance expense includes amounts incurred related to outsourcing, restructuring and other amounts deemed to be in excess of normal recurring amounts. |
| (e) | Transition and business optimization costs include professional fees primarily for retail billing and customer care systems enhancements and incentive compensation. |
| (f) | Transaction and merger expenses include costs related to the Merger, outsourcing transition costs and costs related to certain growth initiatives. |
| (g) | Restructuring and other for 2010 includes a gain on termination of a long-term power sales contract and for 2009 primarily represents reversal of certain liabilities accrued in purchase accounting and recorded as other income, partially offset by restructuring and nonrecurring activities. |
| (h) | Expenses incurred to upgrade or expand a generation station reflect noncapital outage costs. |
| (i) | Primarily pre-operating expenses relating to Oak Grove and Sandow 5. |
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Exhibit 99(d)
Energy Future Intermediate Holding Company LLC Consolidated
Adjusted EBITDA Reconciliation
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
| (millions of dollars) | ||||||||
Net income | $ | 213 | $ | 74 | ||||
Income tax benefit | (42 | ) | (93 | ) | ||||
Interest expense and related charges | 315 | 279 | ||||||
Depreciation and amortization | — | — | ||||||
EBITDA | $ | 486 | $ | 260 | ||||
Oncor Holdings distributions | 169 | 216 | ||||||
Interest income | (209 | ) | (4 | ) | ||||
Equity in earnings of unconsolidated subsidiary (net of tax) | (277 | ) | (256 | ) | ||||
Other | — | (1 | ) | |||||
Adjusted EBITDA per Incurrence Covenant | $ | 169 | $ | 215 | ||||
Add Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions) | $ | 1,354 | $ | 1,123 | ||||
Adjusted EBITDA per Restricted Payments Covenants | $ | 1,523 | $ | 1,338 | ||||
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Exhibit 99(e)
ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC
AN ENERGY FUTURE HOLDINGS CORP. ENTERPRISE
CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2010
AND
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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GLOSSARY
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
2009 Audited Financial Statements | Oncor Holdings’ audited financial statements for the year ended December 31, 2009 included in EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2009 filed on February 19, 2010 (Commission File No. 001-12833) | |
Bondco | Refers to Oncor Electric Delivery Transition Bond Company LLC, a wholly-owned consolidated bankruptcy-remote financing subsidiary of Oncor that has issued securitization (transition) bonds to recover certain regulatory assets and other costs. | |
Capgemini | Capgemini Energy LP, a provider of business process support services to Oncor | |
Deed of Trust | Deed of Trust, Security Agreement and Fixture Filing, dated as of May 15, 2008, made by Oncor to and for the benefit of The Bank of New York Mellon (formerly The Bank of New York), as collateral agent, as amended | |
EBITDA | Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. | |
EFH Corp. | Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include Oncor and TCEH. | |
EFH Retirement Plan | Refers to the defined benefit pension plan sponsored by EFH Corp., in which Oncor is a participating subsidiary. | |
EFIH | Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings. | |
ERCOT | Electric Reliability Council of Texas, the independent system operator and the regional coordinator of the various electricity systems within Texas | |
ERISA | Employee Retirement Income Security Act of 1974, as amended | |
FASB | Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting | |
FERC | US Federal Energy Regulatory Commission | |
GAAP | generally accepted accounting principles | |
Investment LLC | Refers to Oncor Management Investment LLC, a limited liability company and minority membership interest owner of Oncor (approximately 0.22%), whose managing member is Oncor and whose Class B Interests are owned by certain members of the management team and independent directors of Oncor. | |
IRS | US Internal Revenue Service | |
kWh | kilowatt-hours | |
LIBOR | London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market. | |
Limited Liability Company Agreement | The Second Amended and Restated Limited Liability Company Agreement of Oncor, dated as of November 5, 2008, by and among Oncor Holdings, Texas Transmission and Investment LLC, as amended | |
Luminant | Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas. | |
Merger | The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007. | |
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Merger Agreement | Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp. | |
Moody’s | Moody’s Investors Services, Inc. (a credit rating agency) | |
Oncor | Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings, and/or its wholly-owned consolidated bankruptcy-remote financing subsidiary, Bondco, depending on context. | |
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 Plan | Refers to the Oncor Supplemental Retirement Plan, also referred to herein as the “Supplemental Retirement Plan.” | |
Oncor Ring-Fenced Entities | Refers to Oncor Holdings and its direct and indirect subsidiaries. | |
OPEB | other postretirement employee benefits | |
OPEB plan | Refers to an EFH Corp.-sponsored plan, in which Oncor is a participating subsidiary, that offers certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from the company. | |
PUCT | Public Utility Commission of Texas | |
PURA | Texas Public Utility Regulatory Act | |
purchase accounting | The purchase method of accounting for a business combination as prescribed by US GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs, are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill. | |
REP | retail electric provider | |
S&P | Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc. (a credit rating agency) | |
SARs | Stock Appreciation Rights | |
SARs Plan | Refers to the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan. | |
SEC | US Securities and Exchange Commission | |
Securities Act | Securities Act of 1933, as amended | |
Sponsor Group | Refers collectively to the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P. (KKR), TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman Sachs & Co. (See Texas Holdings below.) | |
TCEH | Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of Energy Future Competitive Holdings Company and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context. | |
Texas Holdings | Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp. | |
Texas Holdings Group | Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities. | |
Texas Transmission | Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of EFH Corp.’s subsidiaries or any member of the Sponsor Group. | |
TXU Energy | Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT. | |
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US | United States of America | |
VIE | variable interest entity | |
This Annual Report occasionally makes references to Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. References to “we,” “our,” “us,” and “the company” are to Oncor Holdings and/or its direct or indirect subsidiaries as apparent in the context. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or any other affiliate.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Member of
Oncor Electric Delivery Holdings Company LLC
Dallas, Texas
We have audited the accompanying consolidated balance sheets of Oncor Electric Delivery Holdings Company LLC and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related statements of consolidated income (loss), comprehensive income (loss), cash flows and membership interests for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Oncor Electric Delivery Holdings Company LLC and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 17, 2011
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC
STATEMENTS OF CONSOLIDATED INCOME (LOSS)
(millions of dollars)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Operating revenues: | ||||||||||||
Affiliated | $ | 1,061 | $ | 1,018 | $ | 1,000 | ||||||
Nonaffiliated | 1,853 | 1,672 | 1,580 | |||||||||
Total operating revenues | 2,914 | 2,690 | 2,580 | |||||||||
Operating expenses: | ||||||||||||
Operation and maintenance | 1,009 | 962 | 852 | |||||||||
Depreciation and amortization | 673 | 557 | 492 | |||||||||
Write off of regulatory assets (Note 5) | — | 25 | — | |||||||||
Income taxes | 193 | 145 | 191 | |||||||||
Taxes other than income taxes | 384 | 385 | 391 | |||||||||
Total operating expenses | 2,259 | 2,074 | 1,926 | |||||||||
Operating income | 655 | 616 | 654 | |||||||||
Other income and deductions: | ||||||||||||
Impairment of goodwill (Note 2) | — | — | 860 | |||||||||
Other income (Note 16) | 36 | 49 | 45 | |||||||||
Other deductions (Note 16) | 8 | 14 | 25 | |||||||||
Nonoperating income taxes | 27 | 28 | 26 | |||||||||
Interest income | 38 | 43 | 45 | |||||||||
Interest expense and related charges (Note 16) | 347 | 346 | 316 | |||||||||
Net income (loss) | 347 | 320 | (483 | ) | ||||||||
Net (income) loss attributable to noncontrolling interests | (70 | ) | (64 | ) | 160 | |||||||
Net income (loss) attributable to Oncor Holdings | $ | 277 | $ | 256 | $ | (323 | ) | |||||
See Notes to Financial Statements. | ||||||||||||
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) (millions of dollars)
|
| |||||||||||
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Net income (loss) | $ | 347 | $ | 320 | $ | (483 | ) | |||||
Other comprehensive income, net of tax effects: | ||||||||||||
Cash flow hedges: | ||||||||||||
Net decrease in fair value of derivatives | — | — | (2 | ) | ||||||||
Comprehensive income (loss) | 347 | 320 | (485 | ) | ||||||||
Comprehensive (income) loss attributable to noncontrolling interests | (70 | ) | (64 | ) | 160 | |||||||
Comprehensive income (loss) attributable to Oncor Holdings | $ | 277 | $ | 256 | $ | (325 | ) | |||||
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC
STATEMENTS OF CONSOLIDATED CASH FLOWS
(millions of dollars)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Cash flows — operating activities: | ||||||||||||
Net income (loss) | $ | 347 | $ | 320 | $ | (483 | ) | |||||
Adjustments to reconcile net income to cash provided by operating activities: | ||||||||||||
Depreciation and amortization | 682 | 522 | 451 | |||||||||
Write off of regulatory assets (Note 5) | — | 25 | — | |||||||||
Deferred income taxes – net taxes – net | 155 | 78 | 159 | |||||||||
Amortization of investment tax credits | (5 | ) | (5 | ) | (5 | ) | ||||||
Reversal of reserve recorded in purchase accounting | — | (10 | ) | — | ||||||||
Impairment of goodwill (Note 2) | — | — | 860 | |||||||||
Bad debt expense | (1 | ) | (3 | ) | 1 | |||||||
Other, net | 1 | 2 | 5 | |||||||||
Changes in operating assets and liabilities: | ||||||||||||
Accounts receivable – trade (including affiliates) | (1 | ) | (29 | ) | (1 | ) | ||||||
Inventories | (4 | ) | (29 | ) | (12 | ) | ||||||
Accounts payable – trade (including affiliates) | (17 | ) | 7 | 6 | ||||||||
Deferred advanced metering system revenues (Note 5) | 11 | 57 | — | |||||||||
Other – assets | 3 | (40 | ) | (141 | ) | |||||||
Other – liabilities | (74 | ) | 55 | (11 | ) | |||||||
Cash provided by operating activities | 1,097 | 950 | 829 | |||||||||
Cash flows — financing activities: | ||||||||||||
Issuance of long-term debt (Note 7) | 475 | — | 1,500 | |||||||||
Repayments of long-term debt (Note 7) | (108 | ) | (104 | ) | (99 | ) | ||||||
Net increase (decrease) in short-term borrowings (Note 6) | (239 | ) | 279 | (943 | ) | |||||||
Proceeds from sale of noncontrolling interests, net of transaction costs (Note 10) | — | — | 1,253 | |||||||||
Distribution to parent of equity sale net proceeds | — | — | (1,253 | ) | ||||||||
Distributions to parent (Note 9) | (169 | ) | (216 | ) | (330 | ) | ||||||
Distributions to noncontrolling interests | (42 | ) | (56 | ) | — | |||||||
Decrease in income tax-related note receivable from TCEH | 37 | 35 | 34 | |||||||||
Excess tax benefit on stock-based incentive compensation | — | — | 10 | |||||||||
Debt discount, financing and reacquisition expenses – net | (15 | ) | (3 | ) | (18 | ) | ||||||
Cash provided by (used in) financing activities | (61 | ) | (65 | ) | 154 | |||||||
Cash flows — investing activities: | ||||||||||||
Capital expenditures | (1,020 | ) | (998 | ) | (919 | ) | ||||||
Cash settlements related to outsourcing contract termination (Note 12) | — | — | 20 | |||||||||
Other | (12 | ) | 16 | 20 | ||||||||
Cash used in investing activities | (1,032 | ) | (982 | ) | (879 | ) | ||||||
Net change in cash and cash equivalents | 4 | (97 | ) | 104 | ||||||||
Cash and cash equivalents — beginning balance | 29 | 126 | 22 | |||||||||
Cash and cash equivalents — ending balance | $ | 33 | $ | 29 | $ | 126 | ||||||
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC
CONSOLIDATED BALANCE SHEETS
(millions of dollars)
| At December 31, | ||||||||
| 2010 | 2009 | |||||||
| ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 33 | $ | 29 | ||||
Restricted cash — Bondco (Note 11) | 53 | 47 | ||||||
Trade accounts receivable from nonaffiliates — net (Note 16) | 254 | 243 | ||||||
Trade accounts and other receivables from affiliates | 182 | 188 | ||||||
Income taxes receivable from EFH Corp. (Note 15) | 72 | — | ||||||
Materials and supplies inventories — at average cost | 96 | 92 | ||||||
Accumulated deferred income taxes (Note 4) | 10 | 10 | ||||||
Prepayments | 75 | 76 | ||||||
Other current assets | 5 | 8 | ||||||
Total current assets | 780 | 693 | ||||||
Restricted cash — Bondco (Note 11) | 16 | 14 | ||||||
Investments and other property (Note 11) | 78 | 72 | ||||||
Property, plant and equipment — net (Note 16) | 9,676 | 9,174 | ||||||
Goodwill (Notes 2 and 16) | 4,064 | 4,064 | ||||||
Note receivable due from TCEH (Note 15) | 178 | 217 | ||||||
Regulatory assets – net — Oncor (Note 5) | 1,266 | 1,363 | ||||||
Regulatory assets – net — Bondco (Note 5) | 516 | 596 | ||||||
Other noncurrent assets | 264 | 51 | ||||||
Total assets | $ | 16,838 | $ | 16,244 | ||||
| LIABILITIES AND MEMBERSHIP INTERESTS | ||||||||
Current liabilities: | ||||||||
Short-term borrowings (Note 6) | $ | 377 | $ | 616 | ||||
Long-term debt due currently — Bondco (Note 7) | 113 | 108 | ||||||
Trade accounts payable | 125 | 129 | ||||||
Income taxes payable to EFH Corp. (Note 15) | — | 5 | ||||||
Accrued taxes other than income taxes | 133 | 137 | ||||||
Accrued interest | 108 | 104 | ||||||
Other current liabilities | 109 | 106 | ||||||
Total current liabilities | 965 | 1,205 | ||||||
Long-term debt, less amounts due currently — Oncor (Note 7) | 4,783 | 4,335 | ||||||
Long-term debt, less amounts due currently — Bondco (Note 7) | 550 | 661 | ||||||
Accumulated deferred income taxes (Notes 1 and 4) | 1,516 | 1,369 | ||||||
Investment tax credits | 32 | 37 | ||||||
Other noncurrent liabilities and deferred credits (Note 16) | 1,996 | 1,879 | ||||||
Total liabilities | 9,842 | 9,486 | ||||||
Commitments and contingencies (Note 8) | ||||||||
Membership interests (Note 9): | ||||||||
Capital account | 5,546 | 5,397 | ||||||
Accumulated other comprehensive income (loss), net of tax effects | (2 | ) | (2 | ) | ||||
Oncor Holdings membership interest | 5,544 | 5,395 | ||||||
Noncontrolling interests in subsidiary | 1,452 | 1,363 | ||||||
Total membership interests | 6,996 | 6,758 | ||||||
Total liabilities and membership interests | $ | 16,838 | $ | 16,244 | ||||
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC
STATEMENTS OF CONSOLIDATED MEMBERSHIP INTERESTS
(millions of dollars)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Capital account: | ||||||||||||
Balance at beginning of period | $ | 5,397 | $ | 5,307 | $ | 7,643 | ||||||
Net income (loss) attributable to Oncor Holdings | 277 | 256 | (323 | ) | ||||||||
Distributions paid to parent | (169 | ) | (216 | ) | (1,583 | ) | ||||||
Capital contributions (a) | 40 | 50 | — | |||||||||
Effect of sale of noncontrolling interests (Notes 9 and 10) | — | — | (406 | ) | ||||||||
Distribution of investment in Oncor Communications Holding Company LLC to parent | — | — | (24 | ) | ||||||||
Other | 1 | — | — | |||||||||
Balance at end of period | 5,546 | 5,397 | 5,307 | |||||||||
Accumulated other comprehensive income (loss), net of tax effects: | ||||||||||||
Balance at beginning of period | (2 | ) | (2 | ) | — | |||||||
Net effects of cash flow hedges | — | — | (2 | ) | ||||||||
Balance at end of period | (2 | ) | (2 | ) | (2 | ) | ||||||
Oncor Holdings membership interest at end of period | 5,544 | 5,395 | 5,305 | |||||||||
Noncontrolling interests in subsidiary (Note 11): | ||||||||||||
Balance at beginning of period | 1,363 | 1,355 | — | |||||||||
Net income (loss) attributable to noncontrolling interests | 70 | 64 | (160 | ) | ||||||||
Distributions to noncontrolling interests | (42 | ) | (56 | ) | (2 | ) | ||||||
Change related to future tax distributions from Oncor | 61 | — | — | |||||||||
Investment | — | — | 1,253 | |||||||||
Effect of sale of noncontrolling interests (Note 10) | — | — | 265 | |||||||||
Other | — | — | (1 | ) | ||||||||
Noncontrolling interests in subsidiary at end of period | 1,452 | 1,363 | 1,355 | |||||||||
Total membership interests at end of period | $ | 6,996 | $ | 6,758 | $ | 6,660 | ||||||
(a) | Reflects noncash settlement of certain income taxes payable arising as a result of the sale of noncontrolling interests in Oncor. |
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. | BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES |
Description of Business
We are a Dallas, Texas-based holding company whose financial statements reflect almost entirely the operations of our direct, majority (approximately 80%) owned subsidiary, Oncor. Oncor is a regulated electricity transmission and distribution company principally engaged in providing delivery services to REPs, including subsidiaries of TCEH, that sell power in the north-central, eastern and western parts of Texas. Distribution revenues from TCEH represented 36% and 38% of total revenues for the years ended December 31, 2010 and 2009, respectively. We are a direct, wholly-owned subsidiary of EFIH, a direct, wholly-owned subsidiary of EFH Corp. With the closing of the Merger on October 10, 2007, EFH Corp. became a subsidiary of Texas Holdings, which is controlled by the Sponsor Group, and we and EFIH were formed. See “Glossary” for definition of terms and abbreviations, including the Merger.
References in this report to “we,” “our,” “us,” and “the company” are to Oncor Holdings and/or its direct or indirect subsidiaries as apparent in the context. The financial statements reflect almost entirely the operations of Oncor; consequently, there are no separate reportable business segments.
Our consolidated financial statements include the indirect, bankruptcy-remote financing subsidiary, Bondco. This financing subsidiary was organized for the limited purpose of issuing specified securitization (transition) bonds in 2003 and 2004. Bondco 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.
Various “ring-fencing” measures have been taken to enhance our credit quality. These measures serve to mitigate our and Oncor’s credit exposure to the Texas Holdings Group and to reduce the risk that our assets and liabilities or those 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. Such measures include, among other things: Oncor’s sale of a 19.75% equity interest to Texas Transmission in November 2008; maintenance of separate books and records for the Oncor Ring-Fenced Entities; our board of directors and Oncor’s board of directors being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group, including TXU Energy and Luminant, and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or other obligations of any member of the Texas Holdings Group. We and Oncor do not bear any liability for debt or contractual obligations of the Texas Holdings Group, and vice versa. Accordingly, our operations are conducted, and our cash flows are managed, independently from the Texas Holdings Group.
See Note 10 for discussion of noncontrolling interests sold by Oncor in November 2008.
Basis of Presentation
Our consolidated financial statements have been prepared in accordance with US GAAP and on the same basis as our 2009 Audited Financial Statements. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated. Subsequent events have been evaluated through the date these consolidated financial statements were issued.
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Consolidation of Variable Interest Entities
A VIE is an entity with which we have a relationship or arrangement that indicates some level of control over the entity or results in economic risks to us. We adopted amended accounting standards on January 1, 2010 that require consolidation of a VIE if we have: a) the power to direct the significant activities of the VIE and b) the right or obligation to absorb profit and loss from the VIE (primary beneficiary). The previous standards did not require power to direct significant activities of the VIE in order to consolidate. No additional VIEs were consolidated as a result of the adoption of these accounting standards.
Income Taxes
EFH Corp. files a consolidated federal income tax return. Effective with the November 2008 sale of equity interests in Oncor (see Note 10), Oncor became a partnership for US federal income tax purposes, and subsequently EFH Corp.’s share of partnership income is included in its consolidated federal income tax return. Our tax sharing agreement with Oncor and EFH Corp. was amended in November 2008 to include Texas Transmission and Investment LLC. The tax sharing agreement provides for the calculation of tax liability substantially as if we and Oncor file our own income tax returns, and requires tax payments to members determined on that basis (without duplication for any income taxes paid by our subsidiaries). Deferred income taxes are provided for temporary differences between our book and tax bases of assets and liabilities.
Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, are determined in accordance with the provisions of accounting guidance for income taxes and for uncertainty in income taxes. The accounting guidance for rate-regulated enterprises requires the recognition of regulatory assets or liabilities if it is probable such deferred tax amounts will be recovered from, or returned to, customers in future rates. Investment tax credits are amortized to income over the estimated lives of the related properties.
We classify interest and penalties expense related to uncertain tax positions as current provision for/in lieu of income taxes as discussed in Note 4.
Use of Estimates
Preparation of our financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates or assumptions during the current year.
Derivative Instruments and Mark-to-Market Accounting
Oncor has from time-to-time entered into derivative instruments, specifically interest rate swaps, to hedge interest rate risk. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, the fair value of each derivative is required to be recognized on the balance sheet as a derivative asset or liability and changes in the fair value recognized in net income, unless criteria for certain exceptions are met. This recognition is referred to as “mark-to-market” accounting.
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Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for “hedge accounting,” which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met. A cash flow hedge mitigates the risk associated with the variability of the future cash flows related to an asset or liability (e.g., debt with variable interest rate payments), while a fair value hedge mitigates risk associated with fixed future cash flows (e.g., debt with fixed interest rate payments). In accounting for cash flow hedges, derivative assets and liabilities are recorded on the balance sheet at fair value with an offset to other comprehensive income to the extent the hedges are effective. Amounts remain in accumulated other comprehensive income, unless the underlying transactions become probable of not occurring, and are reclassified into net income as the related transactions (hedged items) settle and affect net income. Fair value hedges are recorded as derivative assets or liabilities with an offset to net income, and the carrying value of the related asset or liability (hedged item) is adjusted for changes in fair value with an offset to net income. If the fair value hedge is settled prior to the maturity of the hedged item, the cumulative fair value gain or loss associated with the hedge is amortized into income over the remaining life of the hedged item. To qualify for hedge accounting, a hedge must be considered highly effective in offsetting changes in fair value of the hedged item. Assessment of the hedge’s effectiveness is tested at least quarterly throughout its term to continue to qualify for hedge accounting. Hedge ineffectiveness, even if the hedge continues to be assessed as effective, is immediately recognized in net income. Ineffectiveness is generally measured as the cumulative excess, if any, of the change in value of the hedging instrument over the change in value of the hedged item.
Revenue Recognition
Revenue from delivery services are recorded under the accrual method of accounting. Revenues are recognized when delivery services are provided to customers on the basis of periodic cycle meter readings and include an estimate for revenues earned from the meter reading date to the end of the period adjusted for the impact of weather (unbilled revenue).
Impairment of Goodwill and Other Intangible Assets
We evaluate goodwill for impairment at least annually. The impairment tests performed are based on determinations of enterprise value using discounted cash flow analyses, comparable company equity values and any relevant transactions indicative of enterprise values. See Note 16 for details of goodwill and other intangible assets and Note 2 for discussion of a goodwill impairment charge recorded in 2008.
System of Accounts
Our accounting records have been maintained in accordance with the FERC Uniform System of Accounts as adopted by the PUCT.
Defined Benefit Pension Plans and Other Postretirement Employee Benefit (OPEB) Plans
Oncor participates in an EFH Corp. pension plan that offers benefits based on either a traditional defined benefit formula or a cash balance formula and an OPEB plan that offers certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from Oncor. Oncor also offers its own supplemental retirement plan (Oncor Plan) to qualified employees. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. See Note 13 for additional information regarding pension and OPEB plans.
Stock-Based Incentive Compensation
In November 2008, Oncor implemented the SARs Plan for certain management that purchased equity interests in the company indirectly by investing in Investment LLC. SARs have been awarded under the SARs Plan and are being accounted for based upon the provisions of guidance for share-based payment. See Note 14 for information regarding stock-based compensation, including SARs granted to certain members of Oncor’s board of directors.
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Fair Value of Nonderivative Financial Instruments
The carrying amounts for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value due to the short maturity of such instruments. The fair values of other financial instruments, for which carrying amounts and fair values have not been presented, are not materially different than their related carrying amounts. The following discussion of fair value accounting standards applies primarily to our determination of the fair value of assets in the pension and OPEB plan trusts as presented in Note 13.
Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a “mid-market” valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.
We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:
· |
Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. | |||
· |
Level 2 valuations use inputs, in the absence of actively quoted market prices that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means and other valuation inputs. | |||
· |
Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. |
We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.
Franchise Taxes
Franchise taxes are assessed to Oncor by local governmental bodies, based on kWh delivered and are the principal component of “taxes other than income taxes” as reported in the income statement. Franchise taxes are not a “pass through” item. Rates charged to customers by Oncor are intended to recover the franchise taxes, but Oncor is not acting as an agent to collect the taxes from customers.
Cash and Cash Equivalents
For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents. See Note 11 for details regarding restricted cash.
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Property, Plant and Equipment
Properties are stated at original cost. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead and an allowance for funds used during construction.
Depreciation of property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties based on depreciation rates approved by the PUCT. As is common in the industry, depreciation expense is recorded using composite depreciation rates that reflect blended estimates of the lives of major asset groups as compared to depreciation expense calculated on a component asset-by-asset basis. Depreciation rates include plant removal costs as a component of depreciation expense, consistent with regulatory treatment. Actual removal costs incurred are charged to accumulated depreciation. When accrued removal costs exceed incurred removal costs, the difference is reclassified as a regulatory obligation to retire assets in the future.
Allowance For Funds Used During Construction (AFUDC)
AFUDC is a regulatory cost accounting procedure whereby both interest charges on borrowed funds and a return on equity capital used to finance construction are included in the recorded cost of utility plant and equipment being constructed. AFUDC is capitalized on all projects involving construction periods lasting greater than thirty days. The equity portion of capitalized AFUDC is accounted for as other income. There was no equity AFUDC for the periods presented. See Note 16 for detail of amounts charged to interest expense.
Regulatory Assets and Liabilities
Our financial statements reflect regulatory assets and liabilities under cost-based rate regulation in accordance with accounting standards related to the effect of certain types of regulation. Regulatory decisions can have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 5 for details of regulatory assets and liabilities.
Sale of Noncontrolling Interests
See Note 10 for discussion of accounting for the sale of noncontrolling interests by Oncor in 2008.
2. | GOODWILL IMPAIRMENT |
The 2010 annual goodwill impairment testing performed as of December 1, 2010 determined that Oncor’s estimated fair value (enterprise value) was substantially in excess of our carrying value, resulting in no additional testing being required and no impairment. Key assumptions in the valuation include discount rates, growth of the rate base and return on equity allowed by the regulatory authority.
In the fourth quarter of 2008, we recorded a goodwill impairment charge totaling $860 million, which was not deductible for income tax-related purposes. The impairment primarily arose from the 2008 dislocation in the capital markets that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies.
The impairment determination involved significant assumptions and judgments in estimating enterprise values and the fair values of assets and liabilities. The calculations supporting the impairment determination utilized models that took into consideration multiple inputs, including debt yields, equity prices of comparable companies and other inputs. Those models were generally used in developing long-term forward discount rates for determining enterprise value and fair values of certain individual assets and liabilities. The fair value measurements resulting from such models are classified as Level 3 non-recurring fair value measurements consistent with accounting standards related to the determination of fair value.
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3. | STIPULATION APPROVED BY THE PUCT |
In April 2008, the PUCT entered an order, which became final in June 2008, approving the terms of a stipulation relating to a filing in 2007 by Oncor and Texas Holdings with the PUCT pursuant to Section 14.101(b) of PURA and PUCT Substantive Rule 25.75. Among other things, the stipulation required Oncor to file a rate case no later than July 1, 2008 based on a test year ended December 31, 2007, which it filed in June 2008. The PUCT issued a final order with respect to the rate case in August 2009. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200th District Court of Travis County, Texas. A hearing on the appeal was held in June 2010, and the District Court affirmed the PUCT order in its entirety. Nucor Steel appealed that ruling to the Third Court of Appeals in Austin, Texas in July 2010. Oral argument before the court is scheduled for March 2011.
In addition to commitments Oncor made in its filings in the PUCT review, the stipulation included the following provisions, among others:
· |
Oncor provided a one-time $72 million refund to its REP customers in the September 2008 billing cycle. The refund was in the form of a credit on distribution fee billings. The liability for the refund was previously recorded as part of purchase accounting. | |||
· |
Consistent with a 2006 cities rate settlement, Oncor filed a system-wide rate case in June 2008 based on a test-year ended December 31, 2007. In August 2009, the PUCT issued a final order on this rate case. See Note 5. | |||
· |
The distributions paid by Oncor will be limited 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) for the period beginning October 11, 2007 and ending December 31, 2012, and are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity (see Note 10). | |||
· |
Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. Approximately 72% of this total was spent as of December 31, 2010. This spending does not include the capital spending on Competitive Renewable Energy Zone (CREZ) facilities. | |||
· |
Oncor committed to an additional $100 million in spending over the five-year period ending December 31, 2012 on demand-side management or other energy efficiency initiatives. These additional expenditures will not be recoverable in rates, and this amount was recorded as a regulatory liability as part of purchase accounting and consistent with accounting standards related to the effect of certain types of regulation. | |||
· |
If Oncor’s credit rating is below investment grade with two or more rating agencies, TCEH will post a letter of credit in an amount of $170 million to secure TXU Energy’s payment obligations to Oncor. | |||
· |
Oncor agreed not to request recovery of goodwill or any future impairment of the goodwill in its rates. |
4. | INCOME TAXES |
The components of our income taxes are as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Reported in operating expenses: | ||||||||||||
Current: | ||||||||||||
US federal | $ | (6 | ) | $ | 69 | $ | 37 | |||||
State | 21 | 17 | 17 | |||||||||
Deferred: | ||||||||||||
US federal | 183 | 67 | 142 | |||||||||
State | — | (3 | ) | — | ||||||||
Amortization of investment tax credits | (5 | ) | (5 | ) | (5 | ) | ||||||
Total | 193 | 145 | 191 | |||||||||
Reported in other income and deductions: | ||||||||||||
Current: | ||||||||||||
US federal | 55 | 13 | 8 | |||||||||
State | 1 | 1 | 1 | |||||||||
Deferred federal | (29 | ) | 14 | 17 | ||||||||
Total | 27 | 28 | 26 | |||||||||
Total income tax expense | $ | 220 | $ | 173 | $ | 217 | ||||||
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Reconciliation of income taxes computed at the US federal statutory rate to income taxes:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Income (loss) before income taxes | $ | 567 | $ | 493 | $ | (266 | ) | |||||
Income taxes at the US federal statutory rate of 35% | $ | 198 | $ | 173 | $ | (93 | ) | |||||
Goodwill impairment | — | — | 301 | |||||||||
Amortization of investment tax credits – net of deferred tax effect | (5 | ) | (5 | ) | (5 | ) | ||||||
Amortization (under regulatory accounting) of statutory tax rate changes | (3 | ) | (2 | ) | (3 | ) | ||||||
Texas margin tax, net of federal tax benefit | 13 | 12 | 11 | |||||||||
Medicare subsidy | (1 | ) | (6 | ) | (5 | ) | ||||||
Nondeductible losses (gains) on benefit plan investments | (1 | ) | (1 | ) | 4 | |||||||
Other, including audit settlements | 19 | 2 | 7 | |||||||||
Income tax expense | $ | 220 | $ | 173 | $ | 217 | ||||||
Effective rate | 38.8% | 35.1% | — | |||||||||
At December 31, 2010 and 2009, net amounts of $1.506 billion and $1.359 billion, respectively, were reported in the balance sheets as accumulated deferred income taxes. These amounts include $1.459 billion and $1.280 billion, respectively, related to our investment in the Oncor partnership.
At December 31, 2010 and 2009, we had $13 million and $10 million of alternative minimum tax (AMT) credit carryforwards, respectively, available to offset future tax sharing payments. The AMT credit carryforwards have no expiration date.
Accounting For Uncertainty in Income Taxes
Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable.
EFH Corp. and its subsidiaries file income tax returns in US federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of EFH Corp. and its subsidiaries’ income tax returns for the years ending prior to January 1, 2003 are complete, but the tax years 1997 through 2002 remain in appeals with the IRS. An IRS audit of tax years 2003 to 2006 is in progress and is expected to be completed in 2011. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginning after 2002.
The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in our consolidated balance sheet, during the years ended December 31, 2010 and 2009:
| 2010 | 2009 | 2008 | ||||||||||
Balance at January 1, excluding interest and penalties | $ | 71 | $ | 122 | $ | 111 | ||||||
Additions based on tax positions related to prior years | 31 | 22 | 41 | |||||||||
Reductions based on tax positions related to prior years | (20 | ) | (73 | ) | (30 | ) | ||||||
Balance at December 31, excluding interest and penalties | $ | 82 | $ | 71 | $ | 122 | ||||||
Of the balance at December 31, 2010, $71 million represents tax positions for which the uncertainty relates to the timing of recognition for tax purposes. The disallowance of such positions would not affect the effective tax rate, but would accelerate the payment of cash under the tax sharing agreement to an earlier period.
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Noncurrent liabilities included a total of $18 million and $20 million in accrued interest at December 31, 2010 and 2009, respectively. Amounts recorded related to interest and penalties totaled a benefit of $1 million and $5 million in the years ended December 31, 2010 and 2009, respectively, as a result of reversals of previously accrued amounts, and an expense of $6 million (including $2 million recorded as goodwill) in the year ended December 31, 2008 (all after tax amounts). The federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferred income taxes.
With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), should EFH Corp. or we sustain such positions on income tax returns previously filed, our liabilities recorded would be reduced by $11 million, resulting in increased net income and a favorable impact on the effective tax rate.
We do not expect the total amount of liabilities recorded related to uncertain tax positions will significantly increase or decrease within the next 12 months.
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5. | REGULATORY ASSETS AND LIABILITIES |
Recognition of regulatory assets and liabilities and the amortization periods over which they are expected to be recovered or refunded through rate regulation reflect the decisions of the PUCT. Components of the regulatory assets and liabilities are provided in the table below. Amounts not earning a return through rate regulation are noted.
| Remaining Rate Recovery/Amortization Period at December 31, 2010 | Carrying Amount | |||||||||||
| December 31, 2010 | December 31, 2009 | |||||||||||
Regulatory assets: | ||||||||||||
Generation-related regulatory assets securitized by transition bonds (a)(f) | 5 years | $ | 647 | $ | 759 | |||||||
Employee retirement costs | 4 years | 63 | 80 | |||||||||
Employee retirement costs to be reviewed (b)(c) | To be determined | 75 | 41 | |||||||||
Employee retirement liability (a)(c)(d) | To be determined | 910 | 768 | |||||||||
Self-insurance reserve (primarily storm recovery costs) — net | 6 years | 117 | 137 | |||||||||
Self-insurance reserve to be reviewed (b)(c) | To be determined | 135 | 106 | |||||||||
Nuclear decommissioning cost under-recovery (a)(c)(e) | Not applicable | — | 85 | |||||||||
Securities reacquisition costs (pre-industry restructure) | 6 years | 55 | 62 | |||||||||
Securities reacquisition costs (post-industry restructure) | Terms of related debt | 26 | 27 | |||||||||
Recoverable amounts in lieu of deferred income taxes — net | | Life of related asset or liability | | 117 | 68 | |||||||
Rate case expenses | Largely 3 years | 6 | 9 | |||||||||
Rate case expenses to be reviewed (b)(c) | To be determined | 4 | 1 | |||||||||
Advanced meter customer education costs (c) | 9 years | 8 | 4 | |||||||||
Deferred conventional meter depreciation | 10 years | 60 | 14 | |||||||||
Energy efficiency performance bonus | Not applicable | 11 | 9 | |||||||||
Deferred third-party transmission service (a)(c) | 1 year | 8 | — | |||||||||
Total regulatory assets | 2,242 | 2,170 | ||||||||||
Regulatory liabilities: | ||||||||||||
Nuclear decommissioning cost over-recovery (a)(c)(e) | Not applicable | 206 | — | |||||||||
Estimated removal costs | Life of utility plant | 28 | — | |||||||||
Gain on reacquired debt | 7 years | 25 | — | |||||||||
Committed spending for demand-side management initiatives (a) | 2 years | 53 | 78 | |||||||||
Deferred advanced metering system revenues | 9 years | 68 | 57 | |||||||||
Investment tax credit and protected excess deferred taxes | Various | 39 | 44 | |||||||||
Over-collection of transition bond revenues (a)(f) | 5 years | 33 | 27 | |||||||||
Energy efficiency programs (a) | Not applicable | 8 | 5 | |||||||||
Total regulatory liabilities | 460 | 211 | ||||||||||
Net regulatory asset | $ | 1,782 | $ | 1,959 | ||||||||
(a) | Not earning a return in the regulatory rate-setting process. |
(b) | Costs incurred since the period covered under the last rate review. |
(c) | Recovery is specifically authorized by statute, subject to reasonableness review by the PUCT. |
(d) | Represents unfunded liabilities recorded in accordance with pension and OPEB accounting standards. |
(e) | Offset by an intercompany payable to/receivable from TCEH. See Note 15. |
(f) | Bondco net regulatory assets of $516 million at December 31, 2010 consist of $549 million included in generation-related regulatory assets net of the regulatory liability for over-collection of transition bond revenues of $33 million. Bondco net regulatory assets of $596 million at December 31, 2009 consist of $623 million included in generation-related regulatory assets net of the regulatory liability for over-collection of transition bond revenues of $27 million. |
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The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act enacted in March 2010 reduce, effective 2013, the amount of OPEB costs deductible for federal income tax purposes by the amount of the Medicare Part D subsidy received by the EFH Corp. OPEB plans in which we participate. Under income tax accounting rules, deferred tax assets related to accrued OPEB liabilities must be reduced immediately for the future effect of the legislation. Accordingly, in the first quarter of 2010, our deferred tax assets were reduced by $42 million. All of this amount was recorded as a regulatory asset (before gross-up for liability in lieu of deferred income taxes) as the additional amounts due related to income taxes are expected to be recoverable in our future rates.
As a result of purchase accounting, in 2007 the carrying value of certain generation-related regulatory assets securitized by transition bonds, which have been reviewed and approved by the PUCT for recovery but without earning a rate of return, was reduced by $213 million. This amount will be accreted to other income over the recovery period remaining at October 10, 2007 (approximately nine years).
On August 31, 2009, the PUCT issued a final order on Oncor’s rate review filed in June 2008. The rate review included a determination of the recoverability of regulatory assets at December 31, 2007, including the recoverability period of those assets deemed allowable by the PUCT. The PUCT’s findings included denial of recovery of certain regulatory assets primarily related to business restructuring costs and rate case expenses, which resulted in a $25 million charge ($16 million after tax) in the third quarter of 2009 reported as write off of regulatory assets.
In September 2008, the PUCT approved a settlement for Oncor to recover its estimated future investment for advanced metering deployment. Oncor began billing the advanced metering surcharge in the January 2009 billing month cycle. The surcharge is expected to total $1.023 billion over the 11-year recovery period and includes a cost recovery factor of $2.19 per month per residential retail customer and $2.39 to $5.15 per month for non-residential retail customers. Oncor accounts for the difference between the surcharge billings for advanced metering facilities and the allowed revenues under the surcharge provisions, which are based on expenditures and an allowed return, as a regulatory asset or liability. Such differences arise principally as a result of timing of expenditures. As indicated in the table above, the regulatory liability at December 31, 2010 totaled $68 million.
In accordance with the PUCT’s August 2009 order in Oncor’s rate review, the remaining net book value and anticipated removal cost of existing conventional meters that are being replaced by advanced meters are being charged to depreciation and amortization expense over an 11-year cost recovery period.
See Note 15 for additional information regarding nuclear decommissioning cost recovery.
6. | BORROWINGS UNDER CREDIT FACILITIES |
At December 31, 2010, Oncor had a $2.0 billion secured revolving credit facility, expiring October 10, 2013, to be used for working capital and general corporate purposes, issuances of letters of credit and support for any commercial paper issuances. Oncor may request increases in the commitments under the facility in any amount up to $500 million, subject to the satisfaction of certain conditions. Amounts borrowed under the facility, once repaid, can be borrowed again from time to time. Borrowings are classified as short-term on the balance sheet.
Oncor’s credit facility is secured equally and ratably with all of its other secured indebtedness by a first priority lien on property it acquired or constructed for the transmission and distribution of electricity. The property is mortgaged under the Deed of Trust. On September 3, 2010, Oncor amended the Deed of Trust to eliminate its ability to release the lien upon satisfaction and discharge of its obligations under the revolving credit facility (see Note 7).
At December 31, 2010, Oncor had outstanding borrowings under the credit facility totaling $377 million with an interest rate of 0.53% and outstanding letters of credit totaling $6 million. At December 31, 2009, Oncor had outstanding borrowings under the credit facility totaling $616 million with an interest rate of 0.58%.
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Subject to the limitations described below, borrowing capacity available under the credit facility at December 31, 2010 and December 31, 2009 was $1.495 billion and $1.262 billion, respectively. The availability at both dates excludes $122 million of commitments from a subsidiary of Lehman Brothers Holding Inc. that has filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. As described in Note 7, the Deed of Trust permits Oncor to secure other indebtedness with the lien of the Deed of Trust up to the aggregate of (i) the amount of available bond credits, and (ii) 85% of the fair value of certain property additions that could be certified to the Deed of Trust collateral agent. At December 31, 2010, the available bond credits were approximately $1.386 billion and the amount of potential indebtedness that could be secured by property additions, subject to a certification process, was $1.161 billion.
Under the terms of the revolving credit facility, the commitments of the lenders to make loans to Oncor are several and not joint. Accordingly, if any lender fails to make loans to Oncor, Oncor’s available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the facility.
Borrowings under the credit facility bear interest at per annum rates equal to, at Oncor’s option, (i) adjusted LIBOR plus a spread of 0.275% to 0.800% (depending on the ratings assigned to Oncor’s senior secured debt) or (ii) a base rate (the higher of (1) the prime rate of JPMorgan Chase Bank, N.A. and (2) the federal funds effective rate plus 50 basis points). Under option (i) and based on Oncor’s ratings as of December 31, 2010, its LIBOR-based borrowings, which apply to all outstanding borrowings at December 31, 2010, bear interest at LIBOR plus 0.275%.
A facility fee is payable at a rate per annum equal to 0.100% to 0.200% (depending on the rating assigned to Oncor’s senior secured debt) of the commitments under the facility. Based on Oncor’s ratings at December 31, 2010, the facility fee is 0.100%. A utilization fee is payable on the average daily amount of borrowings in excess of 50% of the commitments under the facility at a rate per annum equal to 0.125% per annum.
The credit facility contains customary covenants for facilities of this type, restricting, subject to certain exceptions, Oncor and its subsidiary from, among other things:
· |
incurring additional liens; | |
· |
entering into mergers and consolidations; | |
· |
selling certain assets, and | |
· |
making acquisitions and investments in subsidiaries. |
Under the credit facility, Oncor must observe certain customary reporting requirements and other affirmative covenants. In addition, the credit facility requires that Oncor maintain a consolidated senior debt-to-capitalization ratio of no greater than 0.65 to 1.00. For purposes of this ratio, debt is calculated as indebtedness defined in the credit facility (principally, the sum of long-term debt, any capital leases, short-term debt and debt due currently in accordance with US GAAP). The debt calculation excludes transition bonds issued by Bondco but includes the unamortized fair value discount related to Bondco. Equity is calculated as membership interests determined in accordance with US GAAP. At December 31, 2010, Oncor was in compliance with these covenants.
The credit facility contains certain customary events of default for facilities of this type, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments under the facility.
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7. | LONG-TERM DEBT |
At December 31, 2010 and 2009, our long-term debt consisted of the following:
| At December 31, | ||||||||
| 2010 | 2009 | |||||||
Oncor (a): | ||||||||
6.375% Fixed Senior Notes due May 1, 2012 | $ | 376 | $ | 700 | ||||
5.950% Fixed Senior Notes due September 1, 2013 | 524 | 650 | ||||||
6.375% Fixed Senior Notes due January 15, 2015 | 500 | 500 | ||||||
5.000% Fixed Senior Notes due September 30, 2017 | 324 | — | ||||||
6.800% Fixed Senior Notes due September 1, 2018 | 550 | 550 | ||||||
5.750% Fixed Senior Notes due September 30, 2020 | 126 | — | ||||||
7.000% Fixed Debentures due September 1, 2022 | 800 | 800 | ||||||
7.000% Fixed Senior Notes due May 1, 2032 | 500 | 500 | ||||||
7.250% Fixed Senior Notes due January 15, 2033 | 350 | 350 | ||||||
7.500% Fixed Senior Notes due September 1, 2038 | 300 | 300 | ||||||
5.250% Fixed Senior Notes due September 30, 2040 | 475 | — | ||||||
Unamortized discount | (42 | ) | (15 | ) | ||||
Total Oncor | 4,783 | 4,335 | ||||||
Oncor Electric Delivery Transition Bond Company LLC (b): | ||||||||
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010 | — | 13 | ||||||
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013 | 101 | 130 | ||||||
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015 | 145 | 145 | ||||||
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012 | 131 | 197 | ||||||
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016 | 290 | 290 | ||||||
Unamortized fair value discount related to transition bonds | (4 | ) | (6 | ) | ||||
Less amount due currently | (113 | ) | (108 | ) | ||||
Total Oncor Electric Delivery Transition Bond Company LLC | 550 | 661 | ||||||
Total long-term debt (c) | $ | 5,333 | $ | 4,996 | ||||
| ||||
(a) | Secured by first priority lien on certain transmission and distribution assets equally and ratably with all of Oncor’s other secured indebtedness. See Deed of Trust Amendment below for additional information. | |||
(b) | The transition bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset. | |||
(c) | According to our organizational documents, Oncor Holdings (parent) is prohibited from directly incurring indebtedness for borrowed money. | |||
Debt-Related Activity in 2010
Debt Repayments
Repayments of long-term debt in 2010 totaled $108 million and represent transition bond principal payments at scheduled maturity dates.
Issuance of New Senior Secured Notes
In September 2010, Oncor issued $475 million aggregate principal amount of 5.250% senior secured notes maturing in September 2040 (2040 Notes). Oncor used the net proceeds of approximately $465 million from the sale of the notes to repay borrowings under the revolving credit facility, including loans under the revolving credit facility made by certain of the initial purchasers or their affiliates, and for general corporate purposes. The notes are secured by the first priority lien described below, and are secured equally and ratably with all of Oncor’s other secured indebtedness.
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Interest on the 2040 Notes is payable in cash semiannually in arrears on March 30 and September 30 of each year, beginning on March 30, 2011. Oncor may redeem the notes, in whole or in part, at any time, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. The notes also contain customary events of default, including failure to pay principal or interest on the notes when due.
The 2040 Notes were issued in a private placement and have not been registered under the Securities Act. Oncor has agreed, subject to certain exceptions, to register with the SEC notes having substantially identical terms as the 2040 Notes (except for provisions relating to the transfer restriction and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the 2040 Notes. Oncor has agreed to use commercially reasonable efforts to cause the exchange offer to be completed within 315 days after the issue date of the 2040 Notes, or if required, to use commercially reasonable efforts to have one or more shelf registration statements declared effective within the later of 180 days after such shelf registration statement filing obligation arises and 270 days after the issue date of the 2040 Notes. If Oncor does not comply with this obligation (a registration default), the annual interest rate on the notes will increase by 50 basis points per annum until the earlier of the expiration of the registration default or the second anniversary of the issue date of the 2040 Notes.
Debt Exchange
In September 2010, Oncor announced an offer to exchange up to $350 million of its outstanding 6.375% senior secured notes due 2012 and up to $325 million of its outstanding 5.950% senior secured notes due 2013 (collectively, the Original Notes) for newly issued 5.000% senior secured notes due 2017 (2017 Notes) and newly issued 5.750% senior secured notes due 2020 (2020 Notes, and together with the 2017 Notes, New Notes), respectively. In October 2010, Oncor issued approximately $324 million aggregate principal amount of the 2017 Notes and approximately $126 million aggregate principal amount of the 2020 Notes in exchange for an equivalent principal amount of the respective Original Notes validly tendered. Oncor did not receive any cash proceeds from the exchange. Under accounting guidelines, we recorded the exchange transaction related to the $324 million aggregate principal amount of 6.375% senior secured notes due 2012 as a debt retirement, which resulted in a fair value discount totaling $25 million and a gain deferred as a regulatory liability totaling $25 million. We recorded the exchange transaction related to the $126 million aggregate principal amount of the 5.950% senior secured notes due 2013 as a debt modification.
The New Notes have not been registered under the Securities Act. In connection with the issuance of the New Notes, Oncor agreed, subject to certain exceptions, to register with the SEC notes having substantially identical terms as the New Notes (except for provisions relating to the transfer restriction and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the New Notes. Oncor has agreed to use commercially reasonable efforts to cause this exchange offer to be completed within 315 days after the issue date of the New Notes, or if required, to use commercially reasonable efforts to have one or more shelf registration statements declared effective within the later of 180 days after such shelf registration statement filing obligation arises and 270 days after the issue date of the New Notes. If Oncor does not comply with this obligation (a registration default), the annual interest rate on the New Notes will increase 0.50% per annum for the period during which the registration default continues, but not later than the second anniversary of the issue date of the New Notes. Oncor also agreed to file a registration statement containing a “market making prospectus” and to keep it effective, subject to certain exceptions, for a period of ten years after the issue date of the New Notes.
Deed of Trust Amendment
Oncor’s secured indebtedness, including the 2040 Notes and New Notes described above and the revolving credit facility described in Note 6, are secured equally and ratably by a first priority lien on property Oncor acquired or constructed for the transmission and distribution of electricity. The property is mortgaged under the Deed of Trust. The Deed of Trust permits Oncor to secure other indebtedness with the lien of the Deed of Trust up to the aggregate of (i) the amount of available bond credits, and (ii) 85% of the fair value of certain property additions that could be certified to the Deed of Trust collateral agent. At December 31, 2010, the available bond credits were approximately $1.386 billion and the amount of additional potential indebtedness that could be secured by property additions, subject to a certification process, was $1.161 billion.
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On September 3, 2010, Oncor amended the Deed of Trust. Prior to the amendment, the Deed of Trust provided that Oncor could release the lien upon the satisfaction and discharge of all of its obligations under the revolving credit facility. The amendment to the Deed of Trust eliminated this ability to release the lien prior to the payment and performance in full of all obligations secured by the lien of the Deed of Trust.
Debt Repayments in 2009
Repayments of long-term debt in 2009 totaled $104 million and represent transition bond principal payments at scheduled maturity dates.
Maturities
Long-term debt maturities at December 31, 2010, are as follows:
Year | Amount | |||
2011 | $ | 113 | ||
2012 | 494 | |||
2013 | 648 | |||
2014 | 131 | |||
2015 | 639 | |||
Thereafter | 3,467 | |||
Unamortized fair value discount | (4 | ) | ||
Unamortized discount | (42 | ) | ||
Total | $ | 5,446 | ||
Fair Value of Long-Term Debt
The estimated fair value of our long-term debt (including current maturities) totaled $6.136 billion and $5.644 billion at December 31, 2010 and 2009, respectively, and the carrying amount totaled $5.446 billion and $5.104 billion, respectively. The fair value is estimated at the lesser of either the call price or the market value as determined by quoted market prices.
8. | COMMITMENTS AND CONTINGENCIES |
Leases
At December 31, 2010, future minimum lease payments under operating leases (with initial or remaining noncancelable lease terms in excess of one year) were as follows:
Year | Amount | |||
2011 | $ | 14 | ||
2012 | 12 | |||
2013 | 5 | |||
2014 | 4 | |||
2015 | 3 | |||
Thereafter | 4 | |||
Total future minimum lease payments | $ | 42 | ||
Rent charged to operation and maintenance expense totaled $15 million, $11 million and $10 million for the years ended December 31, 2010, 2009 and 2008, respectively.
Capital Expenditures
Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties that was approved by the PUCT in 2008 as discussed in Note 3. As one of the provisions of this stipulation, Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions.
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Efficiency Spending
Oncor is required to annually invest in programs designed to improve customer electricity demand efficiencies to satisfy ongoing regulatory requirements. The 2011 requirement is $45 million.
Guarantees
Oncor has entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions as discussed below.
Oncor is the lessee under various operating leases that obligate it to guarantee the residual values of the leased assets. At December 31, 2010, both the aggregate maximum amount of residual values guaranteed and the estimated residual recoveries totaled approximately $6 million. These leased assets consist primarily of vehicles used in distribution activities. The average life of the residual value guarantees under the lease portfolio is approximately two years.
In June 2010, for the purpose of obtaining greater access to materials, Oncor guaranteed the repayment of borrowings under a nonaffiliated party’s $20 million credit facility maturing on June 7, 2011. The nonaffiliated party’s borrowings under the credit facility are limited to inventory produced solely to satisfy the terms of a contract with Oncor. Oncor would be entitled to the related inventory upon repayment of the credit facility (or payment to nonaffiliated party). At December 31, 2010, the nonaffiliated party had borrowings of approximately $1.5 million under the facility.
Legal/Regulatory Proceedings
In October 2010, the PUCT established Docket No. 38780 for the remand of Docket No. 20381, the 1999 wholesale transmission charge matrix case. A joint settlement agreement was entered into effective October 6, 2003. This settlement resolves disputes regarding wholesale transmission pricing and charges for the period of January 1997 through August 1999, the period prior to the September 1, 1999 effective date of the legislation that authorized 100% postage stamp pricing for ERCOT wholesale transmission. Since a series of appeals has become final, the 1999 matrix docket has been remanded to the PUCT to address two additional issues.
The first issue is the wholesale transmission transition mechanism for the period of September 1999 through December 1999. The disputed issue is whether the PUCT should have allowed the transition mechanism to continue for the last four months of 1999. The appealing parties (Texas Municipal Power Agency, the City of Denton, the City of Garland and GEUS (f/k/a Greenville Electric Utility System)) argued that the transition mechanism was not authorized in the September 1, 1999 100% postage stamp pricing legislation. Oncor’s transmission deficit position was mitigated by approximately $8 million in the last four months of 1999 through the transition mechanism. If the appealing parties prevail, Oncor may have to pay up to the full amount of approximately $8 million. It is anticipated that the issue will be contested and the amounts paid to settle the issue could be subject to negotiation. It is also unclear whether interest would be added. If the PUCT rules adversely and interest is added, Oncor’s liability could be as high as $11 million.
The second issue is the San Antonio City Public Service Board’s (CPSB) claim that the PUCT did not have the authority to reduce CPSB’s requested Transmission Cost of Service (TCOS) revenue requirement. CPSB’s initial TCOS rate was in effect from 1997 through 2000. Since the period of January 1997 through August 1999 is incorporated in the joint settlement, CPSB’s remaining claim is for the period of September 1999 through December 2000. In January 2011, CPSB made a filing with the PUCT (PUCT Docket No. 39068), seeking an additional $22 million of TCOS revenue, including interest, for the 16-month period. If CPSB prevails, Oncor would be responsible for approximately $11 million of the request. Oncor plans to participate in this docket and anticipates that multiple parties will oppose CPSB’s request.
At this time, Oncor cannot predict the outcome of these two matters.
We are involved in other various legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect upon our financial position, results of operations or cash flows.
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Labor Contracts
Certain Oncor employees are represented by a labor union and covered by a collective bargaining agreement with an expiration date of October 25, 2010. Although the expiration date has passed, the current collective bargaining agreement remains in full force and effect under the provisions of an “evergreen clause” contained in the agreement. The parties to the agreement are currently in the process of negotiating a new labor agreement, and it is anticipated that a new agreement will be in place in the first half of 2011. The resolution of this matter is not expected to have a material effect on Oncor’s financial position, results of operations or cash flows.
Environmental Contingencies
Oncor must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. Oncor is in compliance with all current laws and regulations; however, the impact, if any, of changes to existing regulations or the implementation of new regulations is not determinable. The costs to comply with environmental regulations can be significantly affected by the following external events or conditions:
· | changes to existing state or federal regulation by governmental authorities having jurisdiction over control of toxic substances and hazardous and solid wastes, and other environmental matters, and |
· | the identification of additional sites requiring clean-up or the filing of other complaints in which Oncor may be asserted to be a potential responsible party. |
9. | MEMBERSHIP INTERESTS |
On February 15, 2011, our board of directors declared a cash distribution of approximately $15.5 million to be paid to EFIH on February 16, 2011.
During 2010, our board of directors declared, and we paid, the following cash distributions to EFIH:
Declaration Date | Payment Date | Amount Paid | ||||
October 27, 2010 | November 1, 2010 | $28 | ||||
July 28, 2010 | August 3, 2010 | 54 | ||||
May 5, 2010 | May 6, 2010 | 57 | ||||
February 11, 2010 | February 19, 2010 | 30 | ||||
During 2009, our board of directors declared, and we paid, the following cash distributions to EFIH:
Declaration Date | Payment Date | Amount Paid | ||||
November 12, 2009 | November 13, 2009 | $99 | ||||
August 18, 2009 | August 19, 2009 | 59 | ||||
May 19, 2009 | May 20, 2009 | 40 | ||||
February 18, 2009 | March 3, 2009 | 18 | ||||
While there are no direct restrictions on our ability to distribute our net income that are currently material, substantially all of our net income is derived from Oncor. Our board of directors and Oncor’s board of directors, which are composed of a majority of independent directors, can withhold distributions to the extent the boards determine that it is necessary to retain such amounts to meet our expected future requirements.
Oncor’s distributions are limited to its cumulative net income and may not be paid except to the extent Oncor maintains a required regulatory capital structure, as discussed below. At December 31, 2010, $44 million was eligible to be distributed to Oncor’s members after taking into account these restrictions, of which approximately 80% relates to our ownership interest.
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For the period beginning October 11, 2007 and ending December 31, 2012, Oncor’s cash distributions (other than distributions of the proceeds of any issuance of limited liability company units) are limited by the Limited Liability Company Agreement and a stipulation agreement with the PUCT (see Note 3) to an amount not to exceed its cumulative net income determined in accordance with US GAAP, as adjusted by applicable orders of the PUCT. Such adjustments exclude the noncash impacts of purchase accounting (to date, consists of removing the effect of the 2008 $860 million goodwill impairment charge and the cumulative amount of net accretion of fair value adjustments) and deducting two specific cash commitments (the $72 million ($46 million after tax) one-time refund to customers in September 2008 and funds spent as part of the $100 million commitment for additional energy efficiency initiatives of which $46 million ($30 million after tax) has been spent through December 31, 2010). The goodwill impairment charge and refund are described in Notes 2 and 3. At December 31, 2010, $141 million of membership interests was available for distribution under the cumulative net income restriction, of which approximately 80% relates to our ownership interest.
Distributions are further limited by Oncor’s required regulatory capital structure to be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. At December 31, 2010, Oncor’s regulatory capitalization ratio was 59.7% debt and 40.3% equity. The PUCT has the authority to determine what types of debt and equity are included in a utility’s debt-to-equity ratio. For purposes of this ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. The debt calculation excludes transition bonds issued by Bondco. Equity is calculated as membership interests determined in accordance with US GAAP, excluding the effects of purchase accounting (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization). At December 31, 2010, $44 million of membership interests was available for distribution under the capital structure restriction, of which approximately 80% relates to our ownership interest. In January 2011, Oncor filed for a rate review with the PUCT and 203 cities that, among other things, requested a revised regulatory capital structure of 55% debt to 45% equity, which if approved as requested, would further limit Oncor’s distributions.
Effect of Sale of Noncontrolling Interests — The total amount of proceeds from the sale of noncontrolling interests in Oncor (discussed further in Note 10) was less than the carrying value of the interests sold by $265 million, which reflects the fact that Oncor’s carrying value after purchase accounting is based on the Merger value, while the noncontrolling interests sale value did not include a control premium. The difference was accounted for as a reduction of membership interests.
As a result of the sale of the noncontrolling interests and the application of rules for income tax accounting related to outside basis differences, activity in 2008 reflects an increase in the balance of noncurrent accumulated deferred income taxes of $141 million and a decrease in total membership interests by the same amount.
Equity Contributions— As a result of the Merger, all outstanding unvested stock-based incentive compensation awards previously granted by EFH Corp. to Oncor employees vested and such employees became entitled to receive the $69.25 per share Merger consideration. The settlement of these awards totaled $24 million and was accounted for as an equity contribution from EFH Corp., as was the settlement of $4 million of cash incentive compensation awards. See Note 14 for further discussion of stock-based compensation, including a SARs Plan implemented in November 2008.
In March 2008, we distributed our investment in an entity with telecommunications-related activities that are not part of current operations totaling $24 million to EFIH.
10. | NONCONTROLLING INTERESTS |
In November 2008, Oncor sold equity interests to Texas Transmission for $1.254 billion in cash. Texas Transmission is an entity indirectly owned by a private investment group led by OMERS Administration Corporation, acting through its infrastructure investment entity, Borealis Infrastructure Management Inc., and the Government of Singapore Investment Corporation, acting through its private equity and infrastructure arm, GIC Special Investments Pte Ltd. Oncor also indirectly sold equity interests to certain members of its’s board of directors and management team. Accordingly, after giving effect to all equity issuances, at December 31, 2010, Oncor’s ownership was as follows: 80.03% held by us, 19.75% held by Texas Transmission and 0.22% held indirectly by certain members of Oncor’s management team and board of directors.
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The proceeds (net of closing costs) of $1.253 billion received by Oncor from Texas Transmission and the members of Oncor’s management team upon completion of these transactions were distributed to us and subsequently distributed to EFIH and ultimately to EFH Corp.
See Note 9 for a discussion of amounts recorded as a reduction of membership interests as a result of the sale of Oncor membership interests.
11. | INVESTMENTS |
Our investments balance consisted of the following:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
Assets related to employee benefit plans, including employee savings programs, net of distributions | $ | 74 | $ | 67 | ||||
Investment in unconsolidated affiliates | 1 | 3 | ||||||
Land | 3 | 2 | ||||||
Total investments | $ | 78 | $ | 72 | ||||
Assets Related to Employee Benefit Plans
The majority of these assets represent cash surrender values of life insurance policies that are purchased to fund liabilities under deferred compensation plans. At December 31, 2009, Oncor began paying the premiums and became the beneficiary of these life insurance policies. EFH Corp. was the previous beneficiary. At December 31, 2010 and 2009, the face amount of these policies totaled $137 million and $138 million, and the net cash surrender values (determined using a Level 2 valuation technique) totaled $53 million and $52 million, respectively. Changes in cash surrender value are netted against premiums paid. Other investment assets held to satisfy deferred compensation liabilities are recorded at market value.
Restricted Cash
| At December 31, 2010 | At December 31, 2009 | |||||||||||||||
| Current Assets | Noncurrent Assets | Current Assets | Noncurrent Assets | |||||||||||||
Customer collections related to transition bonds used only to service debt and pay expenses | $ | 53 | $ | — | $ | 47 | $ | — | ||||||||
Reserve for fees associated with transition bonds | — | 10 | — | 10 | ||||||||||||
Reserve for shortfalls of transition bond charges | — | 6 | — | 4 | ||||||||||||
Total restricted cash | $ | 53 | $ | 16 | $ | 47 | $ | 14 | ||||||||
12. | TERMINATION OF OUTSOURCING ARRANGEMENTS |
In 2008, Oncor commenced a review of certain outsourcing arrangements with Capgemini, Capgemini America, Inc. and Capgemini North America, Inc. (collectively, CgE), and executed a Separation Agreement with CgE. Simultaneous with the execution of that Separation Agreement, EFH Corp. and TCEH entered into a substantially similar agreement with CgE. The Separation Agreements principally provide for (i) notice of termination of the Master Framework Agreements, dated as of May 17, 2004, as amended, between Capgemini and TCEH and Oncor, respectively, and the related service agreements under the Master Framework Agreements and (ii) termination of the joint venture arrangements between EFH Corp. (and its applicable subsidiaries, including Oncor) and CgE. Under the Master Framework Agreements and related services agreements, Capgemini provided to Oncor and EFH Corp.’s and its other subsidiaries outsourced support services, including information technology, customer care and billing, human resources, procurement and certain finance and accounting activities.
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As a result, during the fourth quarter of 2008:
· |
EFH Corp. received approximately $70 million in cash in exchange for the termination of a purchase option agreement pursuant to which subsidiaries of EFH Corp. had the right to “put” to Capgemini (and Capgemini had the right to “call” from a subsidiary of EFH Corp.) EFH Corp.’s 2.9% limited partnership interest in Capgemini and licensed assets, principally software, upon the expiration of the Master Framework Agreements in 2014 or, in some circumstances, earlier. Oncor received $20 million of such proceeds, reflecting its share of the put option value. | |||
· |
The parties entered into a mutual release of all claims under the Master Framework Agreements and related services agreements, subject to certain defined exceptions, and Oncor received $4 million in cash in settlement of such claims.
|
The effects of the termination of the outsourcing arrangements, including an accrued liability of $16 million for incremental costs to exit and transition the services, were included in goodwill under purchase accounting. Oncor incurred $4 million of these exit liabilities during the year ended December 31, 2009. In December 2009, Oncor recorded a $10 million reversal of a portion of these exit liabilities due primarily to a shorter than expected outsourcing services transition period, and this reversal is reflected in other income (see Note 16). The remaining accrual totaling $2 million was settled in 2010.
13. | PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS |
Pension Plan
Oncor is a participating employer in the EFH Retirement Plan (Retirement Plan), a defined benefit pension plan sponsored by EFH Corp. The Retirement Plan is a qualified pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. All benefits are funded by the participating employers. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. The interest component of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasury bonds. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs.
All eligible employees hired after January 1, 2001 participate under the Cash Balance Formula. Certain employees, who, prior to January 1, 2002, participated under the Traditional Retirement Plan Formula, continue their participation under that formula. It is the participating employers’ policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations.
Oncor also participated in an EFH Corp. supplemental retirement plan for certain employees, whose retirement benefits cannot be fully earned under the qualified Retirement Plan, the information for which is included below. Oncor ceased participation in the EFH Corp. supplemental plan and implemented its own supplemental retirement plan effective January 1, 2010. The Oncor Plan covers certain employees whose retirement benefits cannot be fully earned under the qualified EFH Retirement Plan and is substantially similar to the EFH Corp. supplemental retirement plan, except that Oncor acts as sponsor of the plan. At inception, the projected benefit obligation of the Oncor Plan was $32 million, which was 100% funded. Oncor recognized $1 million and $3 million in net pension costs related to the Oncor Plan, primarily composed of interest costs, for the twelve months ended December 31, 2010 and 2009, respectively.
OPEB Plan
Oncor participates with EFH Corp. and other subsidiaries of EFH Corp. to offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service.
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Regulatory Recovery of Pension and OPEB Costs
PURA provides for Oncor’s recovery of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, which in addition to Oncor’s active and retired employees consists largely of active and retired personnel engaged in TCEH’s activities, related to service of those additional personnel prior to the deregulation and disaggregation of EFH Corp.’s businesses effective January 1, 2002. Accordingly, Oncor entered into an agreement with TCEH whereby it assumed responsibility for applicable pension and OPEB costs related to those personnel.
Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Amounts deferred are ultimately subject to regulatory approval. At December 31, 2010 and 2009, Oncor had recorded regulatory assets totaling $1.047 billion and $889 million, respectively, related to pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilities that otherwise would be recorded as other comprehensive income.
Pension and OPEB Costs Recognized as Expense
The pension and OPEB amounts provided herein represent Oncor’s allocated amounts related to EFH Corp.’s plans based on actuarial computations and reflect Oncor’s employee and retiree demographics as described above. Oncor recognized the following net pension and OPEB costs as expense:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Pension cost | $ | 67 | $ | 35 | $ | 15 | ||||||
OPEB cost | 63 | 55 | 44 | |||||||||
Total benefit cost | 130 | 90 | 59 | |||||||||
Less amounts deferred principally as a regulatory asset or property | (93 | ) | (66 | ) | (42 | ) | ||||||
Net amounts recognized as expense | $ | 37 | $ | 24 | $ | 17 | ||||||
EFH Corp. and participating employers use the calculated value method to determine the market-related value of the assets held in the trust. Oncor includes the realized and unrealized gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.
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Detailed Information Regarding Pension and OPEB Benefits
The following pension and OPEB information is based on December 31, 2010, 2009 and 2008 measurement dates:
| Pension Plan | OPEB Plan | |||||||||||||||||||||||
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||||||||||||||
Assumptions Used to Determine Net Periodic Pension and Benefit Cost: | ||||||||||||||||||||||||
Discount rate | 5.90% | 6.90% | 6.55% | 5.90% | 6.85% | 6.55% | ||||||||||||||||||
Expected return on plan assets | 8.00% | 8.25% | 8.25% | 7.60% | 7.64% | 7.90% | ||||||||||||||||||
Rate of compensation increase | 3.71% | 3.75% | 3.70% | — | — | — | ||||||||||||||||||
Components of Net Pension and Benefit Cost: | ||||||||||||||||||||||||
Service cost | $ | 19 | $ | 16 | $ | 15 | $ | 6 | $ | 4 | $ | 4 | ||||||||||||
Interest cost | 106 | 107 | 99 | 52 | 52 | 50 | ||||||||||||||||||
Expected return on assets | (97 | ) | (100 | ) | (101 | ) | (15 | ) | (13 | ) | (19 | ) | ||||||||||||
Amortization of net transition obligation | — | — | — | 1 | 1 | 1 | ||||||||||||||||||
Amortization of prior service cost (credit) | 1 | 1 | 1 | (1 | ) | (1 | ) | (1 | ) | |||||||||||||||
Amortization of net loss | 38 | 11 | 1 | 20 | 12 | 9 | ||||||||||||||||||
Net periodic pension and benefit cost | 67 | 35 | 15 | 63 | 55 | 44 | ||||||||||||||||||
Other Changes in Plan Assets and Benefit Obligations Recognized as Regulatory Assets: | ||||||||||||||||||||||||
Net loss (gain) | 124 | 154 | 320 | 75 | 76 | 45 | ||||||||||||||||||
Prior service cost (credit) | — | — | — | 1 | — | — | ||||||||||||||||||
Amortization of net loss (gain) | (38 | ) | (11 | ) | (1 | ) | (20 | ) | (12 | ) | (9 | ) | ||||||||||||
Amortization of transition obligation (asset) | — | — | — | (1 | ) | (1 | ) | (1 | ) | |||||||||||||||
Amortization of prior service cost | (1 | ) | (1 | ) | (1 | ) | — | 1 | 1 | |||||||||||||||
Purchase accounting adjustment | — | — | — | — | 4 | (4 | ) | |||||||||||||||||
Total recognized as regulatory assets | 85 | 142 | 318 | 55 | 68 | 32 | ||||||||||||||||||
Total recognized in net periodic pension and benefit costs and as regulatory assets | $ | 152 | $ | 177 | $ | 333 | $ | 118 | $ | 123 | $ | 76 | ||||||||||||
| Pension Plan | OPEB Plan | |||||||||||||||||||||||
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||||||||||||||
Assumptions Used to Determine Benefit Obligations at Period End: | ||||||||||||||||||||||||
Discount rate | 5.50% | 5.90% | 6.90% | 5.55% | 5.90% | 6.85% | ||||||||||||||||||
Rate of compensation increase | 3.74% | 3.71% | 3.75% | — | — | — | ||||||||||||||||||
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| Pension Plan | OPEB Plan | |||||||||||||||
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
Change in Projected Benefit Obligation: | ||||||||||||||||
Projected benefit obligation at beginning of year | $ | 1,821 | $ | 1,550 | $ | 899 | $ | 779 | ||||||||
Service cost | 19 | 16 | 6 | 4 | ||||||||||||
Interest cost | 106 | 107 | 52 | 52 | ||||||||||||
Participant contributions | — | — | 14 | 19 | ||||||||||||
Medicare Part D reimbursement | — | — | 3 | 4 | ||||||||||||
Actuarial (gain) loss | 187 | 233 | 83 | 93 | ||||||||||||
Benefits paid | (81 | ) | (85 | ) | (53 | ) | (52 | ) | ||||||||
Projected benefit obligation at end of year | $ | 2,052 | $ | 1,821 | $ | 1,004 | $ | 899 | ||||||||
Accumulated benefit obligation at end of year | $ | 1,894 | $ | 1,685 | $ | — | $ | — | ||||||||
Change in Plan Assets: | ||||||||||||||||
Fair value of assets at beginning of year | $ | 1,219 | $ | 1,059 | $ | 206 | $ | 191 | ||||||||
Actual return (loss) on assets | 160 | 179 | 23 | 30 | ||||||||||||
Employer contributions (a) | 43 | 66 | 18 | 18 | ||||||||||||
Participant contributions | — | — | 14 | 19 | ||||||||||||
Benefits paid | (81 | ) | (85 | ) | (53 | ) | (52 | ) | ||||||||
Fair value of assets at end of year | $ | 1,341 | $ | 1,219 | $ | 208 | $ | 206 | ||||||||
Funded Status: | ||||||||||||||||
Projected benefit obligation at end of year | $ | (2,052 | ) | $ | (1,821 | ) | $ | (1,004 | ) | $ | (899 | ) | ||||
Fair value of assets at end of year | 1,341 | 1,219 | 208 | 206 | ||||||||||||
Funded status at end of year | $ | (711 | ) | $ | (602 | ) | $ | (796 | ) | $ | (693 | ) | ||||
(a) 2009 pension amount includes transfers of investments related to the salary deferral and supplemental retirement plans totaling $31 million. |
| |||||||||||||||
| Pension Plan | OPEB Plan | |||||||||||||||
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
Amounts Recognized in the Balance Sheet Consist of: | ||||||||||||||||
Other current liabilities | $ | (3 | ) | $ | (2 | ) | $ | — | $ | — | ||||||
Other noncurrent liabilities | (708 | ) | (600 | ) | (796 | ) | (693 | ) | ||||||||
Net liability recognized | $ | (711 | ) | $ | (602 | ) | $ | (796 | ) | $ | (693 | ) | ||||
Amounts Recognized as Regulatory Assets Consist of: | ||||||||||||||||
Net loss | $ | 616 | $ | 529 | $ | 296 | $ | 242 | ||||||||
Prior service cost (credit) | — | 1 | (5 | ) | (7 | ) | ||||||||||
Net transition obligation | — | — | 3 | 3 | ||||||||||||
Net amount recognized | $ | 616 | $ | 530 | $ | 294 | $ | 238 | ||||||||
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The following tables provide information regarding the assumed health care cost trend rates.
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
Assumed Health Care Cost Trend Rates – Not Medicare Eligible: | ||||||||
Health care cost trend rate assumed for next year | 9.00% | 8.00% | ||||||
Rate to which the cost trend is expected to decline (the ultimate trend rate) | 5.00% | 5.00% | ||||||
Year that the rate reaches the ultimate trend rate | 2021 | 2016 | ||||||
Assumed Health Care Cost Trend Rates – Medicare Eligible: | ||||||||
Health care cost trend rate assumed for next year | 8.00% | 7.00% | ||||||
Rate to which the cost trend is expected to decline (the ultimate trend rate) | 5.00% | 5.00% | ||||||
Year that the rate reaches the ultimate trend rate | 2021 | 2016 | ||||||
| 1-Percentage Point Increase | 1-Percentage Point Decrease | |||||||
Sensitivity Analysis of Assumed Health Care Cost Trend Rates: | ||||||||
Effect on accumulated postretirement obligation | $133 | $(110) | ||||||
Effect on postretirement benefits cost | 9 | (7) | ||||||
The following table provides information regarding pension plans with projected benefit obligations (PBO) and accumulated benefit obligations (ABO) in excess of the fair value of plan assets.
| At December 31, | ||||||||
| 2010 | 2009 | |||||||
Pension Plans with PBO and ABO in Excess of Plan Assets : | ||||||||
Projected benefit obligations | $2,052 | $1,821 | ||||||
Accumulated benefit obligations | 1,894 | 1,685 | ||||||
Plan assets | 1,341 | 1,219 | ||||||
Pension Plan and OPEB Plan Investment Strategy and Asset Allocations
The investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Equity securities are held to achieve returns in excess of passive indexes by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging international markets. Fixed income securities include primarily corporate bonds from a diversified range of companies, US Treasuries and agency securities and money market instruments. The investment strategy for fixed income investments is to maintain a high grade portfolio of securities which assist in managing the volatility and magnitude of plan contributions and expense.
The target asset allocation ranges of pension plan investments by asset category are as follows:
| Target | ||||
| Allocation | ||||
Asset Category | Ranges | |||
US equities |
15%-50% | |||
International equities | 5%-20% | |||
Fixed income | 40%-70% | |||
Other | 0%-10% |
The investment objective for the OPEB Plan primarily follows the objectives of the Retirement Plan discussed above, while maintaining sufficient cash and short-term investments to pay near-term benefits and expenses. The actual amounts at December 31, 2010 provided below are consistent with our asset allocation targets.
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Fair Value Measurement of Pension Plan Assets
At December 31, 2010 and 2009, pension plan assets measured at fair value on a recurring basis consisted of the following:
| At December 31, 2010 | At December 31, 2009 | |||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
Asset Category | ||||||||||||||||||||||||||||||||
Interest-bearing cash | $ | — | $ | 42 | $ | — | $ | 42 | $ | — | $ | 60 | $ | — | $ | 60 | ||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||
US | 259 | 58 | — | 317 | 207 | 147 | — | 354 | ||||||||||||||||||||||||
International | 152 | 52 | — | 204 | 156 | 48 | — | 204 | ||||||||||||||||||||||||
Fixed income securities: | ||||||||||||||||||||||||||||||||
Corporate bonds (a) | — | 698 | — | 698 | — | 552 | — | 552 | ||||||||||||||||||||||||
US Treasuries | — | 13 | — | 13 | — | 13 | — | 13 | ||||||||||||||||||||||||
Other (b) | — | 58 | — | 58 | — | 27 | — | 27 | ||||||||||||||||||||||||
Preferred securities | — | — | 9 | 9 | — | — | 9 | 9 | ||||||||||||||||||||||||
Total assets |
$ |
411 |
|
$ |
921 |
|
$ |
9 |
|
$ |
1,341 |
|
$ |
363 |
|
$ |
847 |
|
$ |
9 |
|
$ |
1,219 |
| ||||||||
(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s. (b) Other consists primarily of US agency securities. |
| |||||||||||||||||||||||||||||||
There was no change in the fair value of Level 3 assets in the periods presented.
Fair Value Measurement of OPEB Plan Assets
At December 31, 2010 and 2009, OPEB plan assets measured at fair value on a recurring basis consisted of the following:
| At December 31, 2010 | At December 31, 2009 | |||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
Asset Category | ||||||||||||||||||||||||||||||||
Interest-bearing cash | $ | — | $ | 11 | $ | — | $ | 11 | $ | — | $ | 18 | $ | — | $ | 18 | ||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||
US | 61 | 4 | — | 65 | 55 | 12 | — | 67 | ||||||||||||||||||||||||
International | 27 | 4 | — | 31 | 26 | 4 | — | 30 | ||||||||||||||||||||||||
Fixed income securities: | ||||||||||||||||||||||||||||||||
Corporate bonds (a) | — | 54 | — | 54 | — | 49 | — | 49 | ||||||||||||||||||||||||
US Treasuries | — | 1 | — | 1 | — | 1 | — | 1 | ||||||||||||||||||||||||
Other (b) | 41 | 4 | — | 45 | 38 | 2 | — | 40 | ||||||||||||||||||||||||
Preferred securities | — | — | 1 | 1 | — | — | 1 | 1 | ||||||||||||||||||||||||
Total assets | $ | 129 | $ | 78 | $ | 1 | $ | 208 | $ | 119 | $ | 86 | $ | 1 | $ | 206 | ||||||||||||||||
(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s. (b) Other consists primarily of US agency securities. |
| |||||||||||||||||||||||||||||||
There was no significant change in the fair value of Level 3 assets in the periods presented.
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Expected Long-Term Rate of Return on Assets Assumption
The Retirement Plan strategic asset allocation is determined in conjunction with the plan’s advisors and utilizes a comprehensive Asset-Liability modeling study to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.
Retirement Plan | OPEB Plan | |||||||
Asset Class | Expected Long-Term Rate of Return | Plan Type | Expected Long-Term Returns | |||||
US equity securities | 8.4% | 401(h) accounts | 7.7% | |||||
International equity securities | 8.8% | Life Insurance VEBA | 6.7% | |||||
Fixed income securities | 5.9% | Union VEBA | 6.7% | |||||
Preferred securities | 0.0% | Non-Union VEBA | 2.9% | |||||
| 7.7% | 7.1% | |||||||
Significant Concentrations of Risk
The plans’ investments are exposed to risks such as interest rate, capital market and credit risks. EFH Corp. seeks to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to participating employers. While EFH Corp. recognizes the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.
Assumed Discount Rate
EFH Corp. selected the assumed discount rate using the Hewitt Top Quartile yield curve, which is based on actual corporate bond yields and at December 31, 2010 consisted of 141 corporate bonds rated AA or higher as reported by either Moody’s or S&P.
Amortization in 2011
In 2011, amortization of the net actuarial loss and prior service cost for the defined benefit pension plan from regulatory assets into net periodic benefit cost is expected to be $63 million and $1 million, respectively. Amortization of the net actuarial loss, prior service credit, and transition obligation for the OPEB plan from regulatory assets into net periodic benefit cost is expected to be $27 million, a $1 million credit and $1 million, respectively.
Pension and OPEB Plan Cash Contributions
Oncor’s contributions to the benefit plans were as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Pension plan contributions | $ | 40 | $ | 66 | $ | 46 | ||||||
OPEB plan contributions | 18 | 18 | 31 | |||||||||
Oncor Plan contributions | 3 | — | — | |||||||||
Total contributions | $ | 61 | $ | 84 | $ | 77 | ||||||
Oncor’s estimated funding in 2011 of the EFH Corp. pension and OPEB plans and the Oncor Plan is $173 million, $18 million and $3 million, respectively.
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Future Benefit Payments
Estimated future benefit payments to (receipts from) beneficiaries are as follows:
| 2011 | 2012 | 2013 | 2014 | 2015 | 2016-20 | |||||||||||||||||||
Pension benefits | $ | 94 | $ | 100 | $ | 105 | $ | 111 | $ | 117 | $ | 690 | ||||||||||||
OPEB | $ | 51 | $ | 54 | $ | 58 | $ | 62 | $ | 66 | $ | 386 | ||||||||||||
Medicare Part D subsidies | $ | (5 | ) | $ | (5 | ) | $ | (6 | ) | $ | (6 | ) | $ | (7 | ) | $ | (43 | ) | ||||||
Thrift Plan
Employees of Oncor may participate in a qualified savings plan, the EFH Corp. Thrift Plan (Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax applicable payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under law. Employees who earn more than such threshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% of the first 6% of employee contributions for employees who are covered under the Cash Balance Formula of the Retirement Plan, and 75% of the first 6% of employee contributions for employees who are covered under the Traditional Retirement Plan Formula of the Retirement Plan. Employer matching contributions are made in cash and may be allocated by participants to any of the plan’s investment options. Oncor’s contributions to the Thrift Plan totaled $11 million, $11 million and $9 million for the years ended December 31, 2010, 2009 and 2008, respectively.
14. | STOCK-BASED COMPENSATION |
In 2008, Oncor established the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan (the SARs Plan) under which certain of its employees may be granted stock appreciation rights (SARs) payable in cash, or in some circumstances, Oncor units. Two types of SARs may be granted under the SARs Plan. Time-based SARs (Time SARs) vest solely based upon continued employment ratably on an annual basis on each of the first five anniversaries of the grant date. Performance-based SARs (Performance SARs) vest based upon both continued employment and the achievement of a predetermined level of Oncor EBITDA over time, generally ratably over five years based upon annual Oncor EBITDA levels, with provisions for vesting if the annual levels are not achieved but cumulative two- or three-year total Oncor EBITDA levels are achieved. Time and Performance SARs may also vest in part or in full upon the occurrence of certain specified liquidity events and are exercisable only upon the occurrence of certain specified liquidity events. Since the exercisability of the Time and Performance SARs is conditioned upon the occurrence of a liquidity event, compensation expense will not be recorded until it is probable that a liquidity event will occur. Generally, awards under the SARs Plan terminate on the tenth anniversary of the grant, unless the participant’s employment is terminated earlier under certain circumstances.
In February 2009, Oncor also established the Oncor Electric Delivery Company LLC Director Stock Appreciation Rights Plan (the Director SARs Plan) under which certain non-employee members of its board of directors and other persons having a relationship with Oncor may be granted SARs payable in cash, or in some circumstances, Oncor units. SARs granted under the Director SARs Plan vest in eight equal quarterly installments over a two-year period and are exercisable only upon the occurrence of certain specified liquidity events. Since the exercisability of these SARs is conditioned upon the occurrence of a liquidity event, expense will not be recorded until it is probable a liquidity event will occur.
SARs under the SARs Plan and the Director SARs Plan are generally payable in cash based on the fair market value of the SAR on the date of exercise. During the year ended December 31, 2010, Oncor granted 80,000 Time SARs and 80,000 Performance SARS under the SARs Plan. At December 31, 2010, Time SARs vested totaled 4.2 million and Performance SARs vested totaled 2.8 million. No SARs were granted under the SARs Plan during the year ended December 31, 2009. Oncor granted 6.9 million Time SARs and 6.9 Performance SARs under the SARs Plan during the year ended December 31, 2008. Oncor granted 55,000 SARs under the Director SARs Plan during the year ended December 31, 2009, and all such SARs were vested at December 31, 2010. There were no SARs under either plan eligible for exercise at December 31, 2010.
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15. | RELATED-PARTY TRANSACTIONS |
The following represent our significant related-party transactions:
· |
Oncor records revenue from TCEH, principally for electricity delivery fees, which totaled $1.1 billion for the year ended December 31, 2010, and $1.0 billion for each of the years ended December 31, 2009 and 2008. The fees are based on rates regulated by the PUCT that apply to all REPs. The balance sheets at December 31, 2010 and 2009 reflect receivables from TCEH totaling $143 million and $151 million, respectively, primarily related to these electricity delivery fees. These revenues included approximately $2 million for each of the years ended December 31, 2010, 2009 and 2008 pursuant to a transformer maintenance agreement with TCEH.
| |||
· |
Oncor recognizes interest income from TCEH with respect to its generation-related regulatory assets, which have been securitized through the issuance of transition bonds by Bondco. The interest income, which is received on a monthly basis, serves to offset Oncor’s interest expense on the transition bonds. This interest income totaled $37 million, $42 million and $46 million for the years ended December 31, 2010, 2009 and 2008, respectively.
| |||
· |
Incremental amounts payable by Oncor related to income taxes as a result of delivery fee surcharges to customers related to transition bonds are reimbursed by TCEH. Our financial statements reflect a note receivable from TCEH to Oncor of $217 million ($39 million reported as current in trade accounts and other receivables from affiliates) at December 31, 2010 and $254 million ($37 million reported as current in trade accounts and other receivables from affiliates) at December 31, 2009 related to these income taxes. We review economic conditions, TCEH’s credit ratings and historical payment activity to assess the overall collectability of these affiliated receivables. At December 31, 2010, there were no credit loss allowances related to the note receivable from TCEH.
| |||
· |
An EFH Corp. subsidiary charges Oncor for certain administrative services at cost. These costs, which are reported in operation and maintenance expenses, totaled $36 million, $22 million and $24 million for the years ended December 31, 2010, 2009 and 2008, respectively.
| |||
· |
Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility (reported on TCEH’s balance sheet) is funded by a delivery fee surcharge Oncor collects from REPs and remits monthly to TCEH. Delivery fee surcharges totaled $16 million for each of the years ended December 31, 2010, 2009 and 2008. These trust fund assets are established with the intent to be sufficient to fund the estimated decommissioning liability (also reported on TCEH’s balance sheet). Income and expenses associated with the trust fund and the decommissioning liability recorded by TCEH are offset by a net change in Oncor’s intercompany receivable/payable, which in turn results in a change in Oncor’s reported net regulatory asset/liability. A regulatory liability represents the excess of the trust fund balance over the net decommissioning liability, and a regulatory asset represents the excess of the net decommissioning liability over the trust fund balance.
| |||
· |
The change from a regulatory asset of $85 million at December 31, 2009 to a regulatory liability of $206 million at December 31, 2010 reflects a new decommissioning cost estimate completed in the second quarter of 2010. In accordance with regulatory requirements, a new cost estimate is completed every five years. The change reflected lower cost escalation assumptions as compared to the previous estimate, resulting in a decline in the estimated decommissioning liability (see Note 5).
| |||
· |
Oncor has a 19.5% limited partnership interest, with a carrying value of $1 million and $3 million at December 31, 2010 and 2009, respectively, in an EFH Corp. subsidiary holding principally software-related assets. Equity losses related to this interest are reported in other deductions and totaled $2 million, $2 million and $4 million for the years ended December 31, 2010, 2009 and 2008, respectively. These losses primarily represent amortization of software assets held by the subsidiary. |
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· |
Under the terms of a tax sharing agreement, we are obligated to make payments to EFH Corp. in an aggregate amount that is substantially equal to the amount of federal income taxes that we would have been required to pay if we were filing our own corporate income tax return. Also under the terms of the tax sharing agreement, Oncor makes similar payments to Texas Transmission and Investment LLC, pro rata in accordance with their respective membership interests in Oncor, in an aggregate amount that is substantially equal to the amount of federal income taxes that Oncor would have been required to pay if it were filing its own corporate income tax return. In addition, consistent with the tax sharing agreement, we remit to EFH Corp. Texas margin tax payments, which are accounted for as income taxes, calculated as if we were filing our own return. Our results are included in the consolidated Texas state margin tax return filed by EFH Corp. See discussion in Note 1 to Financial Statements under “Income Taxes.” At December 31, 2010, we had amounts due from EFH Corp. under the agreement totaling $72 million. We had amounts due to EFH Corp. related to income taxes totaling $5 million at December 31, 2009. Income tax payments to EFH Corp. in the year ended December 31, 2010 totaled $107 million and Oncor paid $21 million in federal income tax-related payments to Texas Transmission and Investment LLC. | |||
· |
Oncor held cash collateral of $4 million and $15 million at December 31, 2010 and 2009, respectively, from TCEH related to interconnection agreements for generation units being developed by TCEH. The collateral is reported in the balance sheet in other current liabilities. In January 2010, Oncor returned $11 million of the collateral and paid $1 million in interest pursuant to PUCT rules related to these generating units. | |||
· |
Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect transition bond-related charges on behalf of the utility. Under these tariffs, as a result of TCEH’s credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, at December 31, 2010 and 2009, TCEH had posted letters of credit in the amounts of $14 million and $15 million, respectively, for Oncor’s benefit. | |||
· |
In October 2007, Oncor entered into its current $2 billion revolving credit facility with a syndicate of financial institutions and other lenders. The syndicate includes affiliates of GS Capital Partners (a member of the Sponsor Group). Affiliates of GS Capital Partners have from time-to-time engaged in commercial banking transactions with us in the normal course of business. | |||
· |
Affiliates of the Sponsor Group have, and from time-to-time may (1) sell, acquire or participate in the offerings of our debt or debt securities in open market transactions or through loan syndications, and (2) perform various financial advisory, dealer, commercial banking and investment banking services for Oncor and certain of our affiliates for which they have received or will receive customary fees and expenses. | |||
Goldman, Sachs & Co. (Goldman), an affiliate of the Sponsor Group, received $285,000 in fees for serving as a senior co-dealer manager in Oncor’s offer to exchange up to an aggregate of $675 million of senior secured notes for New Notes in a private placement exchange that closed in October 2010. In connection with the exchange offer, Oncor entered into a registration rights agreement with Goldman and the other dealer managers in the exchange. Pursuant to the registration rights agreement, Oncor agreed, subject to certain exceptions, to file a registration statement with the SEC with respect to a registered offer to exchange the New Notes for publicly registered notes, or under certain circumstances, a shelf registration statement to cover resales of the New Notes. Oncor also agreed to file a registration statement containing a “market making prospectus” and to keep it effective, subject to certain exceptions, for a period of ten years after the issue date of the New Notes. See Note 7 for information regarding the debt exchange. | ||||
In September 2010, Oncor completed a $475 million senior secured notes private placement offering. In conjunction with the offering, Oncor entered into a registration rights agreement with various investment banks as representatives of the initial purchasers in the private placement. KKR Capital Markets LLC, an affiliate of KKR (a member of the Sponsor Group) received $125,000 in fees for serving as a co-manager in the offering. See Note 7 for information regarding the debt offering. | ||||
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· | Affiliates of the Sponsor Group have, from time-to-time, and may in the future sell, acquire or participate in offerings of Oncor’s debt or debt securities in open market transactions or through loan syndications. |
See Notes 4, 9, 10 and 13 for information regarding the tax sharing agreement, distributions to EFIH and noncontrolling interests and the allocation of EFH Corp.’s pension and OPEB costs, respectively.
16. | SUPPLEMENTARY FINANCIAL INFORMATION |
Variable Interest Entities
Oncor is the primary beneficiary and consolidates a wholly-owned VIE, Bondco, which was organized for the limited purpose of issuing specific transition bonds and purchasing and owning transition property acquired from Oncor that is pledged as collateral to secure the bonds. Oncor acts as the servicer for this entity to collect transition charges authorized by the PUCT. These funds are remitted to the trustee and used for interest and principal payments on the transition bonds and related costs.
The material assets and liabilities of Bondco are presented separately on the face of our Consolidated Balance Sheet because the assets are restricted and can only be used to settle the obligations of Bondco, and Bondco’s creditors do not have recourse to our general credit or assets.
Our maximum exposure does not exceed our equity investment in Bondco, which was $16 million at both December 31, 2010 and 2009. We did not provide any financial support to Bondco during the years ended December 31, 2010 and 2009.
Other Income and Deductions
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Other income: | ||||||||||||
Accretion of adjustment (discount) to regulatory assets due to purchase accounting | $ | 34 | $ | 39 | $ | 44 | ||||||
Reversal of exit liabilities recorded in connection with the termination of outsourcing arrangements (Note 11) | — | 10 | — | |||||||||
Net gain on sale of other properties and investments | 2 | — | 1 | |||||||||
Total other income | $ | 36 | $ | 49 | $ | 45 | ||||||
Other deductions: | ||||||||||||
Costs related to 2006 cities rate settlement | $ | — | $ | 2 | $ | 13 | ||||||
Professional fees | 4 | 5 | 5 | |||||||||
Equity losses in unconsolidated affiliate (Note 14) | 2 | 2 | 4 | |||||||||
Other | 2 | 5 | 3 | |||||||||
Total other deductions | $ | 8 | $ | 14 | $ | 25 | ||||||
Major Customers
Distribution revenues from TCEH represented 36%, 38% and 39% of total operating revenues for the years ended December 31, 2010, 2009 and 2008, respectively. Revenues from subsidiaries of one nonaffiliated REP collectively represented 12%, 14% and 16% of total operating revenues for the years ended December 31, 2010, 2009 and 2008, respectively. No other customer represented 10% or more of total operating revenues.
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Interest Expense and Related Charges
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Interest expense | $ | 342 | $ | 338 | $ | 314 | ||||||
Amortization of fair value debt discounts resulting from purchase accounting | 2 | 3 | 3 | |||||||||
Amortization of debt issuance costs and discounts | 5 | 7 | 5 | |||||||||
Allowance for funds used during construction – capitalized interest portion | (2 | ) | (2 | ) | (6 | ) | ||||||
Total interest expense and related charges | $ | 347 | $ | 346 | $ | 316 | ||||||
Trade Accounts Receivable
| December 31, | ||||||||
| 2010 | 2009 | |||||||
Gross trade accounts receivable | $ | 389 | $ | 395 | ||||
Trade accounts receivable from TCEH | (133 | ) | (150 | ) | ||||
Allowance for uncollectible accounts | (2 | ) | (2 | ) | ||||
Trade accounts receivable from nonaffiliates — net | $ | 254 | $ | 243 | ||||
Gross trade accounts receivable at December 31, 2010 and 2009 included unbilled revenues of $126 million and $141 million, respectively.
In April 2009, the PUCT finalized a new rule relating to the Certification of Retail Electric Providers. Under the new rule, write-offs of uncollectible amounts owed by REPs are deferred as a regulatory asset. Accordingly, Oncor recognized a $3 million one-time reversal of bad debt expense in 2009 representing bad debt reserves previously recognized for nonaffiliated REP accounts receivable. Due to the commitments made to the PUCT in 2007, Oncor may not recover bad debt expense, or certain other costs and expenses, from ratepayers in the event of a default or bankruptcy by an affiliate REP.
Property, Plant and Equipment
| Composite Depreciation Rate/ Avg. Life at December 31, 2010 | At December 31, | |||||||||||
| 2010 | 2009 | |||||||||||
Assets in service: | ||||||||||||
Distribution | 4.6% / 22.0 years | $ | 9,112 | $ | 8,778 | |||||||
Transmission | 2.9% / 34.6 years | 4,372 | 3,917 | |||||||||
Other assets | 8.5% / 11.8 years | 728 | 579 | |||||||||
Total | 14,212 | 13,274 | ||||||||||
Less accumulated depreciation | 4,810 | 4,444 | ||||||||||
Net of accumulated depreciation | 9,402 | 8,830 | ||||||||||
Construction work in progress | 253 | 321 | ||||||||||
Held for future use | 21 | 23 | ||||||||||
Property, plant and equipment – net | $ | 9,676 | $ | 9,174 | ||||||||
Depreciation expense as a percent of average depreciable property approximated 4.0%, 3.1% and 2.8% for 2010, 2009 and 2008, respectively.
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Intangible Assets
Intangible assets other than goodwill reported in our balance sheet are comprised of the following:
| At December 31, 2010 | At December 31, 2009 | |||||||||||||||||||||||
| Gross Carrying Amount | Accumulated Amortization | Net | Gross Carrying Amount | Accumulated Amortization | Net | |||||||||||||||||||
Identifiable intangible assets subject to amortization included in property, plant and equipment: | ||||||||||||||||||||||||
Land easements |
$ |
201 |
|
$ |
73 |
|
$ |
128 |
|
$ |
188 |
|
$ |
72 |
|
$ |
116 |
| ||||||
Capitalized software | 338 | 142 | 196 | 240 | 104 | 136 | ||||||||||||||||||
Total | $ | 539 | $ | 215 | $ | 324 | $ | 428 | $ | 176 | $ | 252 | ||||||||||||
Aggregate amortization expense for intangible assets totaled $39 million, $27 million and $19 million for the years ended December 31, 2010, 2009 and 2008, respectively. At December 31, 2010, the weighted average remaining useful lives of capitalized land easements and software were 82 years and 5 years, respectively. The estimated aggregate amortization expense for each of the next five fiscal years is as follows:
Year | Amortization Expense | |||
2011 |
|
$41 |
| |
2012 | 33 | |||
2013 | 33 | |||
2014 | 33 | |||
2015 | 33 | |||
At both December 31, 2010 and 2009, goodwill totaling $4.1 billion was reported on the balance sheet. None of this goodwill is being deducted for tax purposes. See Note 2 for discussion of the goodwill impairment.
Other Noncurrent Liabilities and Deferred Credits
| At December 31, | ||||||||
| 2010 | 2009 | |||||||
Retirement plan and other employee benefits | $ | 1,560 | $ | 1,343 | ||||
Liabilities related to subsidiary tax sharing agreement | 295 | 321 | ||||||
Uncertain tax positions (including accrued interest) | 100 | 91 | ||||||
Nuclear decommissioning cost under-recovery payable to affiliate (Note 15) | — | 85 | ||||||
Other | 41 | 39 | ||||||
Total | $ | 1,996 | $ | 1,879 | ||||
Supplemental Cash Flow Information
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Cash payments related to: | ||||||||||||
Interest | $ | 339 | $ | 337 | $ | 284 | ||||||
Capitalized interest | (2 | ) | (2 | ) | (6 | ) | ||||||
Interest paid (net of amounts capitalized) | 337 | 335 | 278 | |||||||||
Income taxes | 128 | 28 | 65 | |||||||||
Noncash investing and financing activities: | ||||||||||||
Noncash construction expenditures (a) | 78 | 61 | 49 | |||||||||
Noncash capital contribution related to settlement of certain income taxes payable (b) | 40 | 50 | — | |||||||||
Noncash distribution of investment to parent | — | — | 24 | |||||||||
Debt exchange transactions - Oncor (Note 7) | 324 | — | — | |||||||||
(a) | Represents end-of-period accruals. |
(b) | Reflects noncash settlement of certain income taxes payable arising as a result of the sale of noncontrolling interests in Oncor. |
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17. | CONDENSED FINANCIAL INFORMATION OF REGISTRANT |
ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF INCOME (LOSS)
(millions of dollars)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Income tax (expense) benefit | $ | (5 | ) | $ | — | $ | 4 | |||||
Equity in earnings (losses) of subsidiary | 282 | 256 | (327 | ) | ||||||||
Net income (loss) | $ | 277 | $ | 256 | $ | (323 | ) | |||||
See Notes to Financial Statements.
CONDENSED STATEMENTS OF CASH FLOWS
(millions of dollars)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Cash provided by operating activities | $ | 169 | $ | 216 | $ | 331 | ||||||
Cash used in financing activities | (169 | ) | (216 | ) | (330 | ) | ||||||
Net change in cash and cash equivalents | — | — | 1 | |||||||||
Cash and cash equivalents — beginning balance | 1 | 1 | — | |||||||||
Cash and cash equivalents — ending balance | $ | 1 | $ | 1 | $ | 1 | ||||||
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(millions of dollars)
| At December 31, | ||||||||
| 2010 | 2009 | |||||||
| ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 1 | $ | 1 | ||||
Income taxes receivable from EFH Corp. | — | 3 | ||||||
Other current assets | 2 | 2 | ||||||
Total current assets | 3 | 6 | ||||||
Investments | 5,889 | 5,804 | ||||||
Total assets | $ | 5,892 | $ | 5,810 | ||||
| LIABILITIES AND MEMBERSHIP INTEREST | ||||||||
Current liabilities: | ||||||||
Other current liabilities | $ | — | $ | 3 | ||||
Total current liabilities | — | 3 | ||||||
Accumulated deferred income taxes | 53 | 91 | ||||||
Other noncurrent liabilities and deferred credits | 295 | 321 | ||||||
Total liabilities | 348 | 415 | ||||||
Membership interest | 5,544 | 5,395 | ||||||
Total liabilities and membership interest | $ | 5,892 | $ | 5,810 | ||||
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
NOTES TO CONDENSED FINANCIAL STATEMENTS
Basis of Presentation
The accompanying unconsolidated condensed balance sheets are presented at December 31, 2010 and 2009, and the accompanying statements of income (loss) and cash flows are presented for the years ended December 31, 2010, 2009 and 2008. We are a Delaware limited liability company wholly-owned by EFIH, which is a wholly owned subsidiary of EFH Corp. As of December 31, 2010, we own approximately 80% of the membership interests in Oncor. Certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules of the SEC. Because the unconsolidated condensed financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the consolidated financial statements and Notes 1 through 16. Our subsidiaries have been accounted for under the equity method. All dollar amounts in the financial statements are stated in millions of US dollars unless otherwise indicated.
References herein to “we,” “our,” “us,” and “the company” are to Oncor Holdings and/or its direct or indirect subsidiaries as apparent in the context.
Distribution Restrictions
While there are no direct restrictions on our ability to distribute our net income that are currently material, substantially all of our net income is derived from Oncor. Our board of directors and Oncor’s board of directors, which are composed of a majority of independent directors, can withhold distributions to the extent the boards determine that it is necessary to retain such amounts to meet our expected future requirements.
Oncor’s distributions are limited to its cumulative net income and may not be paid except to the extent Oncor maintains a required regulatory capital structure, as discussed below. At December 31, 2010, $44 million was eligible to be distributed to Oncor’s members after taking into account these restrictions, of which 80% relates to our ownership interest.
For the period beginning October 11, 2007 and ending December 31, 2012, Oncor’s cash distributions (other than distributions of the proceeds of any issuance of limited liability company units) are limited by the Limited Liability Company Agreement and a stipulation agreement with the PUCT (see Note 3) to an amount not to exceed its cumulative net income determined in accordance with US GAAP, as adjusted by applicable orders of the PUCT. Such adjustments exclude the noncash impacts of purchase accounting (to date, consists of removing the effect of the 2008 $860 million goodwill impairment charge and the cumulative amount of net accretion of fair value adjustments) and deducting two specific cash commitments (the $72 million ($46 million after tax) one-time refund to customers in September 2008 and funds spent as part of the $100 million commitment for additional energy efficiency initiatives of which $46 million ($30 million after tax) has been spent through December 31, 2010). The goodwill impairment charge and refund are described in Notes 2 and 3. At December 31, 2010, $141 million of membership interests was available for distribution under the cumulative net income restriction, of which 80% relates to our ownership interest.
Distributions are further limited by Oncor’s required regulatory capital structure to be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. At December 31, 2010, Oncor’s regulatory capitalization ratio was 59.7% debt and 40.3% equity. The PUCT has the authority to determine what types of debt and equity are included in a utility’s debt-to-equity ratio. For purposes of this ratio, debt is calculated as long-term debt plus unamortized gains on reacquired debt less unamortized issuance expenses, premiums and losses on reacquired debt. The debt calculation excludes transition bonds issued by Bondco. Equity is calculated as membership interests determined in accordance with US GAAP, excluding the effects of purchase accounting (which included recording the initial goodwill and fair value adjustments and the subsequent related impairments and amortization). At December 31, 2010, $44 million of membership interests was available for distribution under the capital structure restriction, of which 80% relates to our ownership interest. In January 2011, Oncor filed for a rate review with the PUCT and 203 cities that, among other things, requested a revised regulatory capital structure of 55% debt to 45% equity, which if approved as requested, would further limit Oncor’s distributions.
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On February 15, 2011, Oncor’s board of directors declared a cash distribution of approximately $16 million to be paid to us on February 16, 2011. During 2010 and 2009, Oncor’s board of directors declared, and Oncor paid to us cash distributions totaling $169 million and $216 million, respectively.
The net proceeds of $1.253 billion from Oncor’s sale of equity interests in November 2008 were distributed to EFIH and ultimately to EFH Corp.
40